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New US energy regulations from the Trump administration can change the future of power markets. A federal regulation is reversing billions of dollars in investments in clean energy, making projects less cost-effective and promoting the expansion of fossil fuels.
For a detailed IRA spending breakout, see Politico’s article. For a high-level overview of important 2025 market changes, see our May blog New Energy Market Regulations and Trends in 2025.
This abrupt change comes when power markets are already stressed due to tight demand and supply conditions. Electricity demand growth rates are rapidly accelerating throughout the American and Canadian markets, driven by data centers, manufacturing, and electrification.
For a detailed regional reserve margins at risk and tight supply and demand condition report, see NERC’s July 15, 2025, Reliability Assessment.
After decades of relatively flat demand, many Independent System Operators (ISOs) and market participants will need to create new market constructs to respond to the sudden growth rates pressuring supply chains. The new federal policies introduce more market barriers because of complex administrative burdens, which will hinder the development of new generation resources.
Despite US energy regulation changes, power markets are designed to respond to tight supply and demand. The increasing cost of electricity is providing strong signals to build new generation.
Federal policies join with the already increasing electricity prices across markets, leading to a contentious debate on resource development. Advocates back fossil fuels for firm, dispatchable resources, while critics argue these changes undermine years of clean energy investment inertia, leading to high capacity price volatility and uneconomic dispatch. For a detailed breakout of forecasted rising prices, see the Resources for the Future article.
The current administration is creating new constraints on determining what resources are built and dispatched economically.
Let’s explore these policy changes, their market barriers, and the evolving power market design to gain a competitive advantage.
The current administration is investing in natural gas and coal resources, encouraging existing units to stay online by rolling back federal emission policies (e.g., EPA rule 111(d) has been abated) and to build new natural gas generating plants. Supporting Trump’s administration, the Department of Energy (DOE) advocates for retaining and investing further in aging coal and natural gas resources.
The administration has also released a White House Statement saying we are in a state of emergency from a short supply of energy. However, the executive order references energy resources by specifying fuels that aren’t likely covered by Inflation Reduction Act (IRA) technology-neutral tax credits, which is not specific to a fuel but require net-zero emissions.
Simultaneously, carbon-free energy projects such as wind, solar, nuclear, and battery storage are losing momentum. This comes from the abrupt clawback of Inflation Reduction Act (IRA) tax credits, a freeze on permits, and stringent construction start dates.
This is limiting “safe harboring” conditions, causing companies to abandon active projects.
$522 billion in unspent IRA funds are tied to planned and active projects facing deadlines to begin construction by 2027 and be fully operational by 2028 to be eligible for the credits. These deadlines are already challenging due to permitting and supply chain disruptions.
The administration's intentions are clear, but their impacts on power markets are not.
The market conditions of 2015, characterized by inexpensive gas, low demand, and limited renewable energy, have officially ended. The next era, unlike the last, will focus on meeting high demand and efficiently using supply, rather than relying solely on the energy transition and the competitiveness of renewable energy and battery storage.
Navigating the next era of US energy regulations will be complex, particularly within disparate ISO regions like PJM, due to changing federal policies and conflicting federal and state rules. PJM regions offer opportunities for system operators to leverage diverse supply stacks and demand – they can also hinder clear investment signals.
Independent power producer (IPP) investors will continue to prioritize risk minimization by understanding power market revenue to ensure a return on investment for new capacity. This is highly dependent on location, among other factors, as Renewable Portfolio Standards (RPS) can influence investment decisions regarding technology and fuel types.
Once cost-effective, carbon-free projects are being abandoned due to the loss of IRA tax credits. With the absence of federal tax credits, the state can influence profit margins, and a state can help determine project viability to either incentivize carbon-free projects or disincentivize fossil fuel projects.
In PJM, states like Illinois and New Jersey have ambitious goals that make new natural gas combined-cycle plants unlikely to be cost-effective. However, such projects may still be viable in states like Pennsylvania, which seeks to meet growing demand, remain a power net-exporter, and embrace traditional generation.
New energy policies and market barriers have made securing financing for US renewable and energy storage projects more complex. However, many of these projects still prove to be cost-effective. Market confidence will take time to recover as participants navigate and overcome both new and existing market challenges, intensified by recent energy policies.
Ultimately, the investors who can account for all market barriers will determine which resources are committed and built.
Permitting obstacles naturally introduce cost and timing uncertainties across all resource types. Though obstacles differ based on the specific resource type, both federal and state governments exert significant influence over all resources.
Trump's executive order has stalled offshore wind development by freezing federal permits, leading to financial setbacks and potential losses of tax credit eligibility for projects. Although some projects are advanced enough in construction to secure IRA funds, many Atlantic offshore wind developments are now paused or abandoned.
For example, three large offshore wind projects, identified through Infrastructure Insights data, are striving to avoid cancellation despite the freeze. (Infrastructure Insights allows users to track project activity in response to various policy decisions.)
Recent court rulings, which have upheld federal agencies' authority to revoke permits despite legal challenges, are contributing to significant investment uncertainty.
The map below uses Infrastructure Insight data, showing offshore wind projects color-coded by status and sized by nameplate capacity.
Source: Yes Energy
Permitting reform, initiated during the Biden administration, addresses permitting inefficiencies by enhancing transparency of the permitting process through the Fast-41 project framework. Fast-41 projects create transparency and coordination across numerous federal agencies and the project sponsor.
The Trump administration is further supporting permitting reform and expanding its scope to include critical mining operations.
According to permitting.gov, Fast-41-covered projects are completing 25% quicker by making the project sponsor and all the agencies more accountable on an established timeline. (The permitting website is a helpful tool to see projects that require federal permitting, including nearly $5 billion in electricity transmission and 21,000 MW of energy capacity.)
The current administration is trying to work with states to facilitate gas pipeline permitting. For instance, a "stop-work order" on offshore wind projects could be lifted in exchange for states allowing pipeline expansion. However, states with ambitious carbon-free goals might pose challenges.
Even if states agree to these deals, knowing that gas infrastructure is likely to be built, permitting is not the sole obstacle to pipeline expansion. The economic attractiveness of new pipelines is diminishing because of declining natural gas demand from end-use customers, driven by heating electrification.
Project sponsors are largely unwilling to fund new pipelines, as the demand from electric-generating plants alone can’t cover the costs.
States have their own hurdles in permitting for energy projects. The prevailing political climate and the proliferation of renewable projects have led numerous counties across the US to tighten restrictions or outright reject renewable energy initiatives.
According to Heatmap News, about one in five counties across the US heavily restrict or ban new wind and solar projects from their survey of public records and local ordinances, which have nearly doubled since 2022.
The US government is actively promoting domestic fossil fuel production. This initiative, in part, stems from a competition with China and its growing global market share of cost-effective clean energy grid components.
As the world increasingly depends on China for components required for a clean energy grid, the US government wants to promote American fossil fuels domestic and abroad. The federal government aims to discourage renewable energy and energy storage manufacturing that relies on Chinese supply chains for raw materials and components.
This strategy under the Trump administration, known as “Foreign Entity of Concern” (FEoC), will deny tax credits for any new resources that received “material assistance” from a “prohibited foreign entity,” which will discourage trade with China.
An executive order further supports FEoC to suppress renewable investment by targeting foreign-produced, carbon-free markets, narrowing IRA tax credit eligibility, prioritizing traditional generation on public lands, and eliminating wind and solar projects.
Though the market is losing future IRA tax credits, it won’t eliminate all carbon-free resources because of existing natural gas supply chain challenges.
While competitive markets in many regions will favor natural gas for additional capacity, some regions will find natural gas cost-prohibitive to energy storage and renewable resources. This is largely because of the scarcity of gas-fired combustion turbines and associated labor, driving up costs and extending lead times.
Generating electricity from natural gas requires substantial capital investment, and procuring turbines and other necessary equipment is increasingly difficult.
The cost and lead times for natural gas turbine parts are escalating. For instance, a GE Vernova turbine currently requires roughly a four-year lead time and costs two to three times more than it did in 2022.
This situation may see some improvement as GE Vernova invests in a new factory to boost component output by 35%. Additionally, the DOE has stated it wants to call on the Defense Production Act to encourage the production of natural gas equipment.
Interpreting future market signals in power markets requires understanding policy changes. Policies often add to the myriad factors that influence electricity prices. Although federal and state regulators face pressure to maintain low consumer prices, long-term operations should sustain high energy and ancillary service prices.
When energy and ancillary service markets artificially suppress prices, it becomes difficult for long-term market operations to accurately interpret market signals.
As the saying goes, the cure to high prices is high prices, so market mechanisms can incentivize the procurement of additional resources and find a more affordable equilibrium to meet demand.
Power market design should provide investment incentives to create a safe environment for procuring resources needed to maintain a reliable grid. As market conditions continuously change, markets anticipate fluctuations and evolve to meet present and future conditions.
Federal and state policy can be a catalyst or a determinant of evolving markets because it provides rewards outside of markets.
The DOE language used to state the energy emergency isn’t necessarily echoed by ISOs. The federal government creates stop-gap measures to preserve aging resources, but market-based solutions should be trusted.
Pennsylvania Governor Josh Shapiro recently complained and threatened litigation against an "unacceptable" rise in capacity market prices, illustrating a similar dynamic at the state level.
In a healthy competitive market, long-term operational planning should be economically focused, driven by market factors. We expect market factors to drive price increases, creating clear signals for the development of generation and demand resources.
The increase in electricity consumer prices comes from supply and demand conditions, where demand growth is outpacing supply for at least the next couple of years. This will continue to push on reliability requirements and reserve margins, triggering more shortage pricing events.
Markets across the country will increase electricity prices at different rates, but the total US electricity demand growth will increase 50% by 2050. US power markets will need to develop 150-160 GW of additional capacity by 2030 (2.5% YoY growth).
However, most resources currently in development to expand capacity are high-risk clean energy projects. This situation raises economic and reliability concerns and creates uncertainty for market participants regarding near-term and long-term operations.
This will raise electricity prices because of the sudden loss of investment in power projects resulting from the removal of tax credits.
A NERA economic study indicates that the removal of IRA Technology-Neutral tax incentives, coupled with high data center demand, will lead to an 8% national electricity price increase by 2026 (7% residential, 10% C&I).
For an example of a market trying to meet demand and balancing additions and retirement conditions, see What to Know about PJM Plant Retirements.
Federal policy intends to influence the market to invest in natural gas for electricity demand and exports. As global natural gas demand rises, gas prices are projected to steadily rise, largely due to increased LNG exports. This assumes that another global event like the Ukraine conflict does not spike gas prices as it did in 2022.
Power markets have been making progress in improving the capacity expansion process to address high prices.
The interconnection queue has been the main focus of recent reform. This queue, initially designed for large, firm-generating resources, struggled to accommodate the diverse range of projects in terms of size and fuel type.
ISOs have made significant strides in reforming the interconnection process. Through stakeholder engagement, they have implemented improvements such as enhanced study processes, cluster prioritization, and economic-risk models to meet substantial loads. However, the full impact of these changes may not be immediately apparent due to extensive backlogs.
Another market mechanism, Effective Load Carrying Capability (ELCC) class ratings or other accreditation methodologies, promotes resources in the interconnection queue that contribute to reliability during periods of high risk.
Resource accreditation methods acknowledge the need for more natural gas and dispatchable thermal generation to firm up intermittent generation. Rewarding resources that perform well during high-risk periods ensures reliability but complicates investment signals for needed resources, varying with the proliferation of different fuels and changing grid conditions.
The plot below illustrates Infrastructure Insights project data, applying PJM's BRA 2026/2027 ELCC rating class for demonstration. Analyzing Yes Energy data can effectively reveal the true market impact of intermittent capacity loss. Relying solely on nameplate capacity can be misleading when assessing reliability requirements.
While the loss of a significant number of IRA carbon-free projects will heavily affect carbon-free targets and environmental standards, it may not impact reliability as much as it seems.
For instance, solar contributes minimally during periods of risk, particularly given increasing winter risk. Furthermore, even CT and combined cycle natural gas units experience a higher discount than in previous market auctions, with high risk due to winterization issues and electric-gas coordination challenges.
Source: Yes Energy and PJM ELCC (ratings applied at the technology level, then aggregated by fuel)
Interconnection queue reforms and ELCC market constructs challenge investment planning but will improve grid reliability.
However, the interconnection queue isn't the sole obstacle.
Permitting, supply chain issues, and conflicting federal and state policies (described above) will also delay projects, keeping costly, inefficient resources online and raising the long-run marginal cost of supply.
Net Cost of New Entry (CONE) studies help break down the long-run marginal cost of supply by providing detailed indicators required to make investment decisions regarding new generating resources by breaking down the costs of new entry. The CONE calculates a reference technology cost to enter the market by calculating fixed and variable costs for different regions.
Quantifying capital cost is complex with many pieces and is sensitive to location (permitting, labor), and timing (supply chain issues).
Net CONE estimates profits by projecting forward electricity prices based on energy and ancillary service (E and AS) revenues, which offset the CONE cost. This analysis helps ISO markets create price stability and developers analyze the optimal technology and location (within an ISO zone or state) for a project to maximize revenue from power markets.
Typically, in North America the reference technologies indicating economically viable generation are combined-cycle (CC) natural gas plants or four-hour battery energy storage systems (BESS).
Wind and solar resources are challenging to analyze within these studies due to the uncertainty from policy incentives and tax credits, and they also have generally lower accredited capacity.
Every four years, we can count on significant policy changes that compel market participants to adapt to new market signal paradigms, attempting to capitalize on opportunities. Market participants are learning when to pause and when to execute decisions based on policy constraints and subsidies.
During high uncertainty and risk, making "no-regret" decisions proves challenging because choices can result in stranded assets, diminished ROI, and elevated customer costs.
With slim reserve margins, acting on comprehensive market signals is critical and requires an understanding of market context.
Yes Energy makes it easy to analyze market data across ISO/trading regions. For instance, high ancillary service prices in a neighboring balance authority could drive exports across interties from the ISO’s market of interest.
Those who quickly grasp the new paradigm and adjust their strategies will gain an advantage.
In many situations, staying the course, despite changing US energy regulations, may be the best action. Our industry is not new to uncertainty, utilizing planning analysis frameworks, modeling, and Yes Energy products to navigate high-uncertainty conditions.
The ability to model both emerging and existing constraints and to build relationships across market factors will help stabilize the market, enabling intelligent growth strategies and maximized profitability.
The future is promising – with more constraints, we can further optimize grid operations and outperform periods when reserve margins were loose and generation was cheaper/subsidized.
Count on us as your trusted resource for navigating market changes and their impact on market data. The Market Monitoring team assists products and customers in tracking and comprehending emerging market constructs influenced by policy, economic, and engineering factors.
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About the author: Rob Strange has over 10 years of experience in analytics and product development for energy solutions. His specializations include integrated DER grid benefits and resource planning by modeling grid capacity, economic conditions, and end-use characteristics. Rob is a senior market analyst on the market monitoring team at Yes Energy, leveraging his analytic experience to track and evaluate how regulatory changes impact energy market data and related market signals.