Published: April 18, 2025

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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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: 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

Published: February 10, 2025

By Concentric Staff Writer

Key takeaways

The new administration of President Donald Trump is reversing policies of President Joe Biden regarding liquified natural gas, such as a U.S. Department of Energy decision almost a year ago to halt permits for new LNG export facilities, which Trump did away with on his first day in office.
The war between Russia and Ukraine is leading Europe to seek natural gas supplies elsewhere, prodding production in the U.S., where LNG export capacity is set to double with the construction of new export facilities.
U.S. House Republicans and others had resisted the release last month of a U.S. Department of Energy Report saying that increasing U.S. export capacity would drive up domestic prices and increase greenhouse gas emissions.

The dynamics around liquified natural gas (LNG), a major U.S. energy export, have been in flux. We are now observing the impact of President Donald Trump and his immediate reversal of the actions taken by President Joe Biden that froze permits for new LNG export terminals.

Biden’s focus had been on mitigating LNG exports in the name of climate change, while Trump stands in sharp opposition to that viewpoint for the U.S., the world’s number one exporter of LNG.

Trump on Jan. 20 reversed the Biden Administration’s pause on LNG exports with an executive order, part of his “Unleashing American Energy” initiative. The move drew praise from natural gas producers.

“There is the initial positive impact of putting people back to work not only with LNG transport, but with the existing ongoing LNG construction sites that are currently under contract but were paused by Biden, as well as several projects that had been permitted and will now be financed and the construction work allowed to begin,” James Flores, CEO, Sable Offshore Corp., said in an online post promoted by DOE.

Flores said the move would cause a wave of LNG exports that would help balance a trade deficit and strengthen America’s energy security.

Additionally, Trump on Feb. 1 announced a 25-percent tariff on imports from Canada and Mexico and 10-percent on Chinese imports to address what he called “an emergency situation” at U.S. borders posed by “illegal aliens and drugs, including deadly fentanyl.”

Trump then put a 30-day pause on the new tariffs a few days later after public statements from Mexican President Claudia Sheinbaum and Canadian Prime Minister Justin Trudeau that they would bolster border security.

China quickly retaliated with tariffs of its own, including a 10-percent tariff on U.S. coal and LNG, to take effect Feb. 10.

U.S. LNG exports rose since halfway through 2024, according to data from the U.S. Energy Information Administration, rising from 356,423 million cubic feet in June 2024 to 376,065 million cubic feet in November.

The LNG export price also rose during that time, from $6.57 per thousand cubic feet to $6.70 per thousand cubic feet between June 2024 and November 2024, according to EIA.

Biden’s efforts to slow U.S. exports faltered when Judge James Cain of the Western District of Louisiana, a Trump appointee, in July put a stay on the Biden LNG export ban, ruling on a request from 16 states. Cain argued that DOE had ignored the stay’s impact on national security, state revenues, employment opportunities, funding for schools and charities, and pollution allegedly caused by increased reliance on foreign energy sources.

In December, Biden’s DOE released a study saying that large amounts of LNG exports will drive up domestic energy prices and thwart greenhouse gas-reduction goals, including development of wind and solar generation.

Republicans in the U.S. House of Representatives pushed back on both Biden’s moratorium and the study. In February 2024, 150 House Republicans called for Biden to reverse his moratorium, saying it is “economically and strategically dangerous and unnecessary.” Noting that other countries are looking for supplies outside of Russia, the moratorium reduces national security and puts strategic markets at risk, the elected officials said.

“Your administration should do everything it can to encourage greater production of clean-burning and reliable natural gas, and to grant the export permits that allow access to global markets,” a Feb. 4, 2024 letter to Biden from the House Republicans says.

The debate occurs as North America’s LNG export capacity is due to more than double between 2024 and 2028, from 114 billion cubic feet per day (Bcf/d) in 2023 to 24.4 Bcf/d in 2028, based on current construction plans, according to EIA data. Over that period, export capacity is projected to grow by 0.8 Bcf/d in Mexico, 2.5 Bcf/d in Canada, and 9.7 Bcf/d in the U.S. from 10 new projects that are currently under construction in the three countries.

Five LNG export projects with a combined export capacity of 9.7 Bcf/d are under construction in the U.S., including Venture Global’s Plaquemines Phase I and Phase II in Port Sulphur, Louisiana and Cheniere Energy’s Corpus Christi Stage III on the Gulf Coast in Texas, both of which began producing LNG in December.

There are also other LNG projects in the works, including QatarEnergy and ExxonMobil’s Golden Pass, NextDecade’s Rio Grande (Phase I), and Port Arthur (Phase I), all in Texas.

Natural gas is also flowing from the U.S. via the Sur de Texas-Tuxpan pipeline to Mexican floating LNG terminals such as the Fast LNG Altamira and Energía Costa Azul LNG export terminal (0.4 Bcf/d export capacity) in Baja, California in western Mexico. Phase II of the later project is due to expand by 1.6 Bcf/d. Five other projects are proposed on the west coast of Mexico, with a combined capacity of 4.5 Bcf/d, according to the EIA.

In the North, gas from western Canada will supply three proposed projects with a combined capacity of 2.5 Bcf/d in British Columbia on Canada’s west coast. They include LNG Canada (export capacity 1.8 Bcf/d) with a plan to begin LNG exports from Train 1 in the summer of 2025; Woodfibre LNG (export capacity 0.3 Bcf/d) with exports beginning in 2027; and Cedar LNG, the nation’s first indigenous-owned project with a capacity of 0.4 Bcf/d, due to begin exports in 2028. Canada has authorized four other LNG expansion projects with a combined capacity of 4.1 Bcf/d.

The relationship between domestic production, imports, and exports have shifted as the production environment in the U.S. has changed. The shale gas boom of the late 2000s reversed trends and led to efforts to reactivate dormant import facilities, some of which were transferred to export beginning in 2016, according to S&P Global. U.S. export capacity sat at 13 bcf/d in 2024, with exports going to Europe, South America, Asia, and North Africa.

The value of LNG exports has exceeded others such as soybeans, corn, and even movies and television entertainment.

DOE’s study issued in December is intended to “provide an updated understanding of the potential effects of U.S. LNG exports on the domestic economy, U.S. households and consumers; communities that live near locations where natural gas is produced or exported; domestic and international energy security, including effects on U.S. trading partners; and the environment and climate,” the agency said.

There is “inherent uncertainty” regarding the state of U.S. LNG exports through 2050, the study says, which added the effort is not intended to be a forecast but rather explore a range of scenarios. DOE is responsible for authorizing exports of LNG under the Natural Gas Act. By 2050, projections of U.S. LNG exports exceed the export volume from LNG projects in operation or under construction, the agency said.

Globally, the market for LNG has been increasing in recent years and re-gasification and import infrastructure is being built, although future demand is uncertain and centers of demand are shifting, DOE said. Overseas countries include LNG as part of their strategies because it supports dispatchable power generation, often from existing infrastructure, which also leads to their policies driving U.S. export dynamics. Europe has been the primary destination for U.S. natural gas historically.

In Europe, policies reducing the usage of fossil fuels, including natural gas, could come into play, but demand for gas and LNG from Asia is expected to increase. By 2050, China is expected to be the largest LNG importer, according to the DOE study.

In analyzing the economic impact of new LNG projects in the U.S., DOE said, “natural gas production and the development of natural gas export infrastructure tends to increase employment in regions and communities where it occurs, but some evidence indicates that jobs often go to people who either move to the area for the jobs or commute from other areas, rather than to long-term residents.”

The U.S. has been a net exporter of LNG since 2016, when the first export terminal in the lower 48 states began operation. Average annual U.S. nameplate export capacity increased from 1.0 Bcf/d in 2016 to 11.9 Bcf/d in 2023, DOE said.

LNG demand growth in the first half of 2024 was driven by double-digit growth in China and India, but the outlook demand is “fragile,” according to the International Energy Agency. The second quarter of 2024 was marked by slacking global LNG production and price volatility. Asian demand was forecast to push up 2024 global demand by 2.5 percent, IEA said.

“Geopolitical instability represents the greatest risk to the short-term outlook. LNG trade has practically halted across the Red Sea since the start of the year, while Russia is increasingly targeting energy infrastructure in Ukraine, including underground gas storage facilities,” IEA said in its quarterly Gas Market Report.

Asia accounted for about 60 percent of the increase in global gas demand over the first half of 2024, with demand increasing by about 10 percent in both China and India.

Production-wise, global LNG supply growth was a scant 2 percent in the first half of 2024. LNG output fell in the second quarter by .5 percent or .5 billion cubic meters (bcm). This was the first quarter-over-quarter decline since Covid-19 lockdowns crippled LNG demand and caused the cancellation of cargos. Feed gas supply issues and unexpected outages drove production declines in the second quarter. But the expansion of U.S. export capability accelerated LNG supply capability in the second half of 2024.

In North America, residential and commercial demand weakened in the first quarter of 2024 because of unseasonably mild weather, but growth in natural gas-fired power generation offset this. Low gas prices in the early part of the year led U.S. upstream suppliers to cut dry gas output, damping gas production downward by 1.5 percent in the U.S. in the second quarter of 2024.

The war in Ukraine is leading European countries to push to diversify their natural gas supply, spurring interest in new projects such as a $44 billion natural gas pipeline in Alaska that would run between the North Slope and Nikiski, along the shore of Cook Inlet.

State corporation Alaska Gasline Development Corp. is leading an effort to develop the pipeline, recently announcing a contractual agreement with Glenfarne Group LLC, according to Alaska Public Media. The 800-mile project has been in the works for decades with its prospects fluctuating depending on costs and demand dynamics. Gov. Mike Dunleavey said that the Trump administration will be more accommodating to the project compared with Biden.

Background information and cited sources

This article drew on sources such as the U.S. DOE, corporate websites, S&P Global, U.S. House documents, the U.S. Energy Information Administration, the International Energy Agency, and Alaska Public Media.

President Donald Trump Jan. 20 executive order

President Donald Trump Feb. 1 executive order

EIA data: U.S. Natural Gas Exports and Re-Exports by Country

Feb. 24 letter to President Joe Biden from U.S. House of Representatives Republicans

EIA Today in Energy report

U.S. House of Representatives

S&P Global

U.S. DOE Study: Energy, Economic, and Environmental Assessment of U.S. LNG Exports

IEA Gas Market Report Q3-2024

Alaska Public Media article

Published: November 8, 2024

By Concentric Staff Writer

After over-riding its membership, on November 4, the national organization responsible for the reliability of the bulk power grid filed with federal energy regulators a suite of proposed new standards for inverter-based resources (IBRs) such as solar, batteries, and wind, to address problems with these systems in recent years.

On November 4, the North American Electric Reliability Corporation (NERC) made four separate filings to the Federal Energy Regulatory Commission (FERC) related to IBRs. NERC filed a petition for approval of two standards related to IBR ride-through performance during system disturbances (PRC-024-4, PRC 029-1); another requiring analysis and mitigation of IBR performance issues (PRC 030-1); a petition for approval of the proposed definition of the new term “Inverter-Based Resource”; and another establishing requirements of disturbance monitoring requirements for IBRs (PRC-028-1 and PRC-002-5).

“The proposed reliability standards are an integral part of NERC’s proposed framework to address IBR performance issues in a comprehensive and holistic manner,” the organization said in the filing for disturbance monitoring requirements for IBRs. “[T]he proposed reliability standards are part of a set of standards that collectively respond to the Commission’s directives for requirements addressing IBR ride-through settings, ride-through performance, data recording, and analysis and mitigation of unexpected IBR performance,” NERC said.

NERC said there has been widespread loss of generating resources—solar photovoltaic, wind, synchronous generation, and battery storage—across multiple “system events.” For example, the Blue Cut Fire in August 2016 in San Bernardino County, California, and the Canyon 2 Fire in October 2017 in Orange County, California, demonstrated a risk to grid reliability as IBRs were unable to ride-through the events. In 2022, NERC analyzed more than 10 grid disturbances involving widespread loss of IBRs, it said.

FERC in its Order No. 901 [RM22-12], approved in October 2023, had required NERC to file the IBR standards by Nov. 4 of this year. After disagreement among members, the NERC Board of Trustees in October invoked the special authority in order to allow the organization to meet the deadline, it said.

That lack of consensus led a NERC committee during an earlier August meeting to recommend that the board invoke its special authority “to ensure that systemic reliability issues associated with IBRs are addressed in a timely manner,” according to NERC documents.

In the Western Interconnection — the power grid that spans several western U.S. states, Canada, and parts of Mexico —IBRs are on the upswing, but they have introduced a number of challenges to reliability. IBRs lack the physical inertia that is inherent to traditional synchronous resources such as coal, gas, and nuclear, creating problems such as fault-induced delayed voltage recovery. IBRs also have trouble with the frequency response that traditional generation provides to the grid.

NERC’s Board of Trustees at an October 8 technical conference successfully revised the IBR standard, allowing it to be approved under a reduced voting threshold compared to its normal voting procedures. At an August meeting in Vancouver, NERC membership was unable to reach consensus on how stringent the standards should be.

FERC’s Order No. 901 required NERC to file the standards on a three-year staggered time frame. The commission required NERC to file IBR disturbance-monitoring data sharing, post-event performance validation, and ride-through performance requirements by November 4, 2024; IBR data and model validation by November 4, 2025; and planning and operational studies for IBRs by November 4, 2026. The Commission also directed NERC to develop and submit a work plan to develop new and revised reliability standards to address the IBR issues in accordance with that timeframe.

According to minutes from the October 8 NERC technical conference, Board of Trustees member Kenneth DeFontes recommended that the board use the special authority in order to file the standards in compliance with FERC’s November 4 deadline.

“[DeFontes] reported that while much of the hard work of NERC’s stakeholders is paying off, with progress made on important IBR reliability standards through the usual standard development process, NERC does not have a clear path forward on the IBR grid disturbance ride through standard,” the minutes say.

DeFontes said the board must consider its options to meet its regulatory responsibilities but noted that the board “does not consider these options lightly.” He also recommended continued participation by NERC members and industry representatives on the standard.

The board approved a package of Milestone 2 standards for IBR “ride-through,” which refers to the capability of solar, wind, and battery devices to continue operating during temporary disturbances or faults on the electrical grid. Inverters will ride-through the disturbance and remain connected to the grid instead of disconnecting immediately when voltage or frequency deviates from normal ranges.

The Milestone 2 standards were approved under NERC’s Project 2020-02, an initiative to develop and update standards for IBRs. NERC had identified that there was a gap in existing reliability standards, which were developed for traditional synchronous generation resources such as coal, gas, and nuclear.

The goals of Project 2020-02 are to update existing standards such as protection and controls, modeling, data, and analysis to make them more suitable for IBRs. These include requirements for more accurate modeling, performance verification, and coordination of protection systems. The initiative also has the goal of defining and enhancing ride-through requirements to establish clear and consistent requirements for IBRs to ride through system disturbances without tripping off.

NERC also has the goal of ensuring an accurate representation of IBRs in grid models, seen as critical for planning and analysis of operational reliability. This includes requirements for verifying that IBR models reflect their performance in the real world.

NERC’s Project 2020-02 included modifications to the PRC-024-4 standard and the development of the PRC-029-1 standard to initiate its development (frequency and voltage ride-through requirements for inverter-based resources), but the latter standard failed to achieve consensus through the usual standard-development process, NERC said.

The NERC board discussed issues surrounding the FERC Order No. 901 directives, including whether or not the proposed reliability standard PRC-029-1 is “just, reasonable, not unduly discriminatory or preferential, in the public interest, helpful to reliability, practical, technically sound, technically feasible, and cost-justified,” according to a NERC memorandum.

On Jan. 17, NERC also submitted its Order No. 901 work plan, which consists of key milestones to meet the FERC directives by the filing deadlines. The Milestone 2 standards, in progress, focus on the development of reliability standards to address disturbance monitoring, performance-based ride-through requirements, and post-event performance validation for registered IBRs by the Nov. 4 deadline.

While Project 2020-02, which addressed generator ride-through directives from FERC Order No. 901 had created controversy, Projects 2021-04 and 2023-02 are on track for timely completion through the usual NERC standard development process, the memorandum says.

FERC’s Order No. 901 cited multiple reports of events with IBRs as the reason NERC should have reliability standards for ride-through frequency and voltage system disturbances. The standards should permit tripping of IBRs only to protect the IBR equipment in scenarios similar to when synchronous generation resources use tripping as protection from internal faults, FERC said. Exceptions should be applied to certain IBRs, and finding consensus around those directives was a part of the main issues addressed during the technical conference, according to NERC.

FERC said NERC must require registered IBRs to continue to perform frequency support during any bulk-power system disturbance and that any new or modified reliability standard must also require registered IBR generator owners and operators to prohibit momentary cessation in the no-trip zone during disturbances.

Under FERC’s order, NERC was required to submit new or modified reliability standards that establish IBR performance requirements, including requirements addressing frequency and voltage ride-through, post-disturbance ramp rates, phase lock loop synchronization, and other known causes of IBR tripping or momentary cessation.

“Therefore, we direct NERC through its standard development process to determine whether the new or modified reliability standards should provide for a limited and documented exemption for certain registered IBRs from voltage ride-through performance requirements. Any such exemption should be only for voltage ride-through performance for those existing IBRs that are unable to modify their coordinated protection and control settings to meet the requirements without physical modification of the IBRs’ equipment,” FERC said in the order.

During deliberations among NERC members, many argued that the proposed PRC-029-1 definition was too broad and ambiguous, particularly the inclusion of phrases like “entire” and “in its entirety,” when referring to a generating plant or facility. Those parties recommended revisions to clarify the definition and ensure it aligns better with Institute of Electrical and Electronics Engineers Standard 2800, which covers interconnection and interoperability of IBRs, and interconnection with associated transmission systems.

Project 2020-02 will enhance reliability by requiring entities to perform energy reliability assessments to evaluate energy assurance and develop corrective action plans to address identified risks, NERC said. These energy reliability assessments should evaluate energy assurance across operations planning, near-term transmission planning, and long-term transmission planning or equivalent time horizons by analyzing the expected resource mix availability and flexibility and the expected availability of fuel during the study period.

According to NERC, IBRs are still being designed and installed without setting their protection and controls in accordance with their physical capabilities.

NERC had solicited comments from the industry as well as original equipment manufacturers on any information on hardware-based limitations that would prevent IBRs from meeting the proposed frequency criteria within PRC-029-1. The organization said 21 individual comments were received, including six from different original equipment manufacturers of IBRs. There were concerns that a draft of PRC 029-1 proposed frequency criteria that went beyond those established in IEEE 2800-2022 and there was a concern that IBR operators would not be able to meet those proposed frequency criteria, as IBR capability limits were hardware-based and inherent to manufacturer design.

Though the organization had failed to reach consensus among its members on some of the standards, the filing of NERC’s new standards will hopefully address the issues with IBRs that have raised their head in the Western Interconnection in recent years.

—

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

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