New Energy Market Regulations and Trends in 2025

2025 kicks off a multiyear period of major market overhauls. As regulations shift and new market structures take shape, market participants must understand what policies will impact their position in the wholesale markets.

This is a continuation of last year’s blog examining key power market regulations that IPPs need to know in 2024. Learn how these regulations have progressed and what new developments you should watch in 2025 and beyond. 

Feel free to follow Yes Energy on LinkedIn or our team at RTO Insider for up-to-the-minute info daily!

In This Blog

• How Might Regulations Impact You in an Evolving Market?
• Intro to Regulatory Benefits and Challenges 
• Despite Uncertainty, Inflation Reduction Act Fuels Clean Energy Growth
• FERC Orders Target Interconnection Queue Bottleneck and Infrastructure
• Texas Energy Fund Falls Short of Goal
• National Energy Emergency and Offshore Wind Freeze
• New Ancillary Services Emerging
• New Markets in Ontario and the Western US
• Conclusion

How Might Regulations Impact You in an Evolving Market?

Let’s consider evolving load profiles, the resource mix, and price formation mechanisms.

The resource mix and load landscape have changed dramatically in the past year. Up through early 2024, US power markets were grappling with electrification and increases in the buildout of variable energy resources (VERs). The steady load growth from electrification has since seen an unprecedented rise driven by data center demand, with some experts forecasting data centers could account for up to 60% of total load growth from 2023 through 2030. 

All these factors contribute to an increasingly widespread demand for flexible, clean, efficient dispatchable generation to manage the changing load shape in concert with reliability concerns raised by the changing resource mix.

With these market factors in mind, what types of power market regulations could impact you in 2025?

Intro to Regulatory Benefits and Challenges 

Firstly, uncertainty around tariff policy and the future of federal policies is introducing price volatility and supply chain risk. Despite this, rapidly falling costs of battery storage development make the current regulatory landscape a mixed bag of increasing challenges and potential benefits. 

The Inflation Reduction Act still provides strong incentives for continuing to develop solar and other renewable resources and disincentives for coal plants. Plus, FERC’s recent orders on interconnection and transmission planning enable the grid to replace aging fossil-based generation. 

Meanwhile, the Texas legislature continues to bolster investment in gas-fired dispatchable generation. This comes as federal offshore wind projects have been paused, and other policy reversals create uncertainty around continued investment in low-carbon technologies. 

Let’s take a closer look at each policy and how it can impact your organization.

Despite Uncertainty, Inflation Reduction Act Fuels Clean Energy Growth

Despite the threat of federal policy reversals and the removal of the Inflation Reduction Act’s (IRA) Investment Tax Credit (ITC), the IRA continues to spur investment. The act passed in 2022, and guidance from the US Department of the Treasury and the IRS in 2024 provided much-needed certainty for developers and investors of renewable resources. 

The IRA extended the 30% ITC and $0.0275/kWh Production Tax Credit (PTC) through 2025. The ITC and PTC are replaced by the Clean Electricity Investment Tax Credit (CEITC) of up to 30% and the Clean Electricity Production Tax Credit (CEPTC) with a base rate of $0.003/kWh or $0.015/kWh for resources that begin operations in 2025.

Solar, wind, and hydro projects are eligible for the tax credit when the percentage of domestically manufactured project components meets IRS thresholds ranging from 20% to 55% (depending on the project’s construction start date). 

The IRS also introduced a “safe harbor” approach, allowing developers to calculate cost percentages based on standardized classifications rather than relying on manufacturer-specific cost data.

FERC Orders Target Interconnection Queue Bottleneck and Infrastructure

Since 2021, FERC has focused on increasing power supply and developing the necessary transmission infrastructure to support it. You can see these priorities with two of FERC’s landmark orders: FERC Order 2023, issued July 2023, which aims to improve the interconnection process, and FERC Order 1920, issued May 2024, which focuses on regional transmission planning and cost allocation. 

FERC Order 2023 looks to reform and streamline grid interconnection processes, which have ballooned to unprecedented levels in recent years because of the surge in renewable and battery storage development. 

The order’s reforms affect three key areas. 

First, it mandates a transition from a first-come, first-served serial process to a first-ready, first-served cluster study process. 

Second, it aims to increase the speed of interconnection queue processing. 

Third, it addresses reforms to incorporate technological advancements in the interconnection process. 

Before this FERC order, all seven RTOs/ISOs had generation interconnection (GI) queues with multiyear backlogs primarily consisting of wind, solar, and battery storage resources. ERCOT, for example, had over 350 GW of GI requests in 2024. For context, ERCOT’s current peak demand is about 85 GW.

Texas Energy Fund Falls Short of Goal

Last year, the Public Utility Commission of Texas (PUCT) implemented the Texas Energy Fund, a $5-billion program providing low-interest loans and grants designed to quickly add 10 GW of new or upgraded gas-fired generation to the ERCOT grid. 

Through April 2025, more than 40% of the originally submitted projects have been withdrawn or denied. This leaves less than 7.5 GW of capacity and about $3.96 billion in requested loans in the fund’s portfolio. The PUCT will advance additional applications to try to reach that 10 GW goal.

This demonstrates how difficult it is to meet rising demand without robust renewable and storage growth because no other resources can be developed so quickly.

This is significant because the Texas Energy Fund was established out of growing concern for adequate, reliable capacity to meet rapidly rising demand amid record-breaking summers and increasing renewable penetration. 

National Energy Emergency and Offshore Wind Freeze

In January 2025, President Donald Trump declared a "national energy emergency" and issued an executive order pausing all federal leasing for offshore wind and freezing new or renewed permitting and loans for all onshore and offshore wind projects.

The national energy emergency gives the president the authority to suspend some environmental regulations. Since January, permitting has been fast-tracked for oil, gas, and mining projects while the permitting for VERs has slowed. 

In April, Trump gave over one third – about 71 GW – of US coal-fired capacity two-year exemptions from the EPA’s Mercury and Air Toxics Standards (MATS) as part of the administration’s effort to boost coal resources. Most recently, Trump halted construction of the fully permitted Empire Wind 1 offshore wind farm in New York. 

Despite this changing environmental landscape, a February EIA report projected that 63 GW of utility-scale generation capacity will be brought online this year, 81% of that being solar and battery storage and only 7% natural gas. Although challenges remain, the energy transition continues to drive increased demand for renewable energy and battery storage resources. 

New Ancillary Services Emerging

ISOs and Regional Transmission Organizations (RTOs) across the country aim to maintain reliability amid evolving market conditions. One way is by creating additional ancillary service markets, which we are seeing in ERCOT, ISO New England (ISO-NE), and the Pennsylvania-New Jersey-Maryland Interconnection (PJM). 

Dispatchable Reliability Reserve Service (DRRS) to Go Live in December 2025

Previously, we detailed ERCOT’s developing Performance Credit Mechanism (PCM), which was being designed in the absence of a traditional capacity market in Texas. As of December 2024, the market design discussions are officially over, and the PCM is canceled. 

However, ERCOT’s Dispatchable Reliability Reserve Service (DRRS) is still moving forward. The DRRS is expected to be implemented in December 2025, following the go-live of ERCOT’s Real-Time Co-Optimization + Batteries (RTC+B) project on December 5. 

DRRS is a new standalone ancillary service from the Texas Legislature’s House Bill 1500 that will provide generators with another revenue stream and incentivize them to be available to run for a longer time. 

Under the current design, resources eligible to provide this service must be able to run at their high sustained limit (HSL) for four hours. Participants may be online generation, energy storage, controllable load resources, and offline generation with a start time of two hours or less. DRRS will be procured and co-optimized in the day-ahead market (DAM) and deployed during the reliability unit commitment (RUC) process. The service will not be co-optimized with energy or other ancillary services in the real-time market.

Because ERCOT’s PCM was cancelled, the design may undergo more changes. Despite being distinct from existing capacity markets, the PCM intended to address a similar “missing money” problem of insufficient revenues in the energy-only market to support adequate entry (and retention) of generation resources. The DRRS may undergo future design changes to address revenue adequacy in the absence of the PCM.

Following ISO New England’s (ISO-NE) DASI initiative, ERCOT is the last US ISO/RTO that doesn’t co-optimize energy and ancillary services pricing and dispatch in both the real-time and day-ahead markets. ERCOT currently only co-optimizes energy and ancillary services in the day-ahead. 

The RTC+B project will introduce real-time co-optimization, and it will change how ERCOT models battery resources to better account for their state of charge. Read more on ERCOT’s RTC+B and co-optimization. 

Day-Ahead Ancillary Service Initiative (DASI, ISO-NE) Launched

ISO New England’s (ISO-NE) new day-ahead ancillary services market design successfully went live in March 2025. The DASI created an ancillary services market in the DAM that is co-optimized with energy in the DAM. The new Day-Ahead Ancillary Service products include Flexible Response Services (FRS) and Energy Imbalance Reserve (EIR). 

The FRS replaces an inefficient “Forward Reserve Market” fast-start spin and non-spin resources to respond to sudden source-loss transmission contingencies. The EIR calls on resources to cover the “energy gap” between the day-ahead cleared supply and forecasted demand.

The DASI improves the ability of system operators and generation owners to respond to the system’s sudden energy shortfalls by dispatching fast-ramping, reserve-capable resources. The ultimate goal is to better align generator financial incentives with ISO operational goals through better market designs.

For more insights, see ISO-NE's Day-Ahead Market Ancillary Service Product Changes. 

PJM Regulation Market Redesign to Go Live in October 2025

PJM is redesigning its regulation market to improve design flaws and better align with other ISOs. Phase 1 of this redesign has a targeted go-live date of October 1, 2025. 

The current regulation market design uses two dispatch signals, one for slow-ramping (Reg A) and one for fast-ramping resources (Reg D). These two signals create suboptimal market clearing and an over-procurement and overvaluation of regulation services.

PJM will address this in two phases. Phase 1, coming October 1, 2025, will change dispatch signals from two bidirectional signals to a single bidirectional signal for all resources to follow. Phase 2, targeted for October 2026, will split the new, single bidirectional signal into two separate products, each a single direction (Reg Up and Reg Down).

These changes aim to better align PJM regulation dispatch with its changing resource mix and improve price formation by better reflecting resources’ actual costs.

New Markets in Ontario and the Western US

Some of the most exciting regulatory developments in 2025 lie in the Western regions that aren’t currently part of an ISO or RTO and in Canada, where formal day-ahead markets are being developed and implemented.

Western Day-Ahead Market Development

CAISO and SPP’s developing independent day-ahead markets are still competing for Western territory as they edge closer to their launch dates.

CAISO’s EDAM Takes Shape

CAISO’s voluntary extended day-ahead market (EDAM) builds off the successes of the real-time energy imbalance market (EIM). 

It’s set to launch with the participation of investor-owned utility (IOU) PacifiCorp on May 1, 2026, and IOU Portland General Electric on October 1, 2026. Other utilities, including the LA Department of Water and Power and the Balancing Authority of Northern California are set to join in 2027 and beyond.

Supporting the expansion of CAISO’s EIM and EDAM is the West-Wide Governance Pathways Initiative, which seeks to shift governance of the markets from CAISO to a proposed independent regional organization (RO). Giving the RO sole authority over the market rules maximizes independence and leverages the existing CAISO market infrastructure, which will help minimize costs and ensure reliability. 

This phase of the Pathways Initiative requires a California law change. The proposed legislation in the “Pathways” Senate Bill 540 was sent to the Senate Judiciary Committee on April 21, 2025, and has until October 12, 2025, for the governor to sign or veto the bill if the legislature passes it. 

SPP Markets+ Advances

SPP currently operates a real-time Western Energy Imbalance Service (WEIS) in the West and is developing a voluntary extended day-ahead market, Markets+. In 2025, FERC approved SPP’s final Markets+ tariff revisions, compliance filing, and most recently, SPP’s funding plans for Markets+ on April 22, 2025. 

SPP’s Markets+ is now in Phase 2 of its development, implementing the Markets+ design from Phase 1 and integrating participants into the market. As of April 16, eight Western entities have signed the agreement and will contribute to $150 million in implementation costs, Bonneville Power Administration (BPA) being the most notable. 

SPP Markets+ has a go-live date for October 1, 2027. 

Concurrently with Markets+, SPP will expand its footprint into the Western Interconnection as part of its RTO Expansion initiative. Seven utilities, primarily in Colorado and Wyoming, will join the SPP RTO footprint, making SPP the first RTO to span two interconnections (East and West) under a single tariff. The seven utilities will make up a new Western balancing area authority (BAA) that is co-optimized with SPP’s East BAA across three direct current (DC) ties. 

SPP’s RTO Expansion will expand all of SPP’s RTO offerings to the Western BAA, including the virtuals market and congestion hedging mechanisms. Both physical and virtual market participants will benefit from this expansion, which will be implemented April 1, 2026.

We’ve looked at all the changes coming to US power markets, but the biggest change to Canadian power markets since their inception just happened in Ontario!

Ontario’s Power System (IESO) Market Renewal Program Launched

Ontario’s power system, the Independent Electricity System Operator (IESO), has just gone nodal through its Market Renewal Program (MRP). This is the first market to go nodal since SPP in 2014. 

On May 1, 2025, IESO brought wide-scale reform to its market by introducing a nodal market with a formal day-ahead market as well as a virtual market. 

With the MRP, IESO introduced greater transparency into its price formation with nodal locational marginal pricing (LMP). Over 970 load and generation nodes have been created, reflecting the costs of congestion and transmission line losses in the IESO system. Introducing the formal DAM and the virtual market (participants can trade on nine virtual zones) increases competition and operational certainty.  

The renewed IESO market is an exciting moment for current and future IESO participants. To learn more about the MRP, read our Ontario Market Renewal Program FAQs.

Conclusion

In 2025, you’re operating in a rapidly evolving regulatory environment. Surging load forecasts driven by data centers combined with major reforms in energy markets, ancillary services, and interconnection processes are reshaping opportunities and risks across North American power markets. Understanding how evolving policies intersect with market dynamics is critical to evaluating their potential impact on your investment and development strategies. 

At the federal level, the IRA tax credits and interconnection queue reform will continue to provide strong price signals for continued support for clean energy investment in renewable and battery storage resources. Policy reversals, the declared US national energy emergency, and other permitting and supply chain uncertainty introduce new market distortions that will likely slow down, but not stop, clean energy development. 

At the state and ISO level, grid operators grapple with the reliability challenges presented by growing renewables, aging dispatchable resources, and unprecedented growth in load forecasts. New markets and new ancillary services are being developed to combat reliability concerns and provide new revenue opportunities for savvy wholesale market participants.

Understanding key regulations in 2025 may highlight opportunities for mitigating risk for your business. 

That’s where we come in. Yes Energy’s market experts, our colleagues at RTO Insider, and our premium suite of power market data offerings are here to help you keep abreast of key regulatory changes potentially impacting your investment strategy. Request a demo or talk to our team to learn more! 

About the author: Tim Hough is a market analyst on the market monitoring team at Yes Energy, specializing in the CAISO, SPP, and Canadian markets. He graduated from Pomona College in 2024, where he pursued his passion in the energy transition by obtaining a degree in environmental analysis and economics