2024 Year in Review

Energy Markets Update

In this newsletter, we cover key factors impacting US energy markets. We focus on AI's impact on energy demand and explore the shift in nuclear energy sentiment during 2024. Additionally, we examine the 2025 outlook for the solar industry. Finally, we discuss how to prepare for winter storms and their effects on natural gas supplies and prices.

Weekly Natural Gas Inventories

Source: EIA

US Energy Market Update

In 2024 we covered a wide range of topics impacting energy markets in North America from the rapid onset of new datacenter demand to the disastrous rollout of the US offshore wind industry. We aim to provide content that is relevant and interesting to our clients. We look forward to continuing that dialogue in 2025. We will end the year with some summaries of some key trends in 2024 that will continue to take shape next year: data center demand growth, a possible revival of nuclear power in the US, and renewable energy growth ahead of the incoming Trump administration.

Spot prices remained low in November across all US power and gas markets. The cost of delivered spot gas averaged under $2/MMbtu in most of the US. Average power rates declined month-over-month outside of small increases in New York and New England.
Source: ISO
The first week of December saw the first substantive cold front of the season in midcontinent and eastern markets. While cold temperatures have subsided, the market did test $14/MMbtu daily gas in New York and New England.
Futures markets are generally finding more support, particularly in 2026 and beyond. Those tenors are up between 7-10% over the past 8 weeks with much of the gains solidifying on the back of last week’s cold snap.
Natural gas stocks peaked at 3,967 bcf headed into the Thanksgiving weekend and have since dropped to 3747 bcf with today’s report of a 190 bcf weekly withdrawal, still a strong position.
Daily flows of gas into Mexico have averaged about 6.5 bcf/d, up about 10% on the year.

Bridging the Power Gap: AI's Impact on Energy Demand

By now, it’s no secret that the rapid integration of power-intensive AI into society is reshaping the landscape of energy demand, requiring a robust expansion of power generation and transmission infrastructure to support burgeoning data centers. This transformation, however, is fraught with challenges, including navigating regulatory red tape and the extensive timelines required for developing new generation assets. Moreover, the question of who bears the financial burden looms large, with potential implications for other ratepayers.

Source: Grid Strategies

A report by the consulting firm Grid Strategies projects that in the next five years, demand for electricity in the United States will grow by 128 GW, or nearly 16% – primarily driven by datacenters and new manufacturing. Only two years ago, FERC forecasts showed 4,375 TWh of energy generation required to meet demand in 2029. Since then, that number has grown by nearly 10% to 4,774 TWh.
In PJM alone, peak summer load is projected to reach about 200,000 MW in the 2032/33 delivery year, up from about 170,000 MW in last year’s forecast. The Virginia Electric and Power Co. zone is expected to see the highest average annual summer load growth over the next 20 years, with just over 5% forecast growth.

Source: Grid Strategies

The power industry is already grappling with the challenges of meeting this demand. The latest PJM capacity auction, for instance, revealed thinning reserve margins, resulting in a staggering 900% increase in prices for the 2025/2026 delivery compared to the previous year.
Certain PJM states, particularly Ohio and Virginia, have become datacenter "hotspots" due to their attractive combination of affordable real estate, robust connectivity, and reliable, cost-effective power. However, this has created a tough situation for local utilities like AEP Ohio, which must balance the substantial power needs of new datacenters with the desire to minimize infrastructure costs for residential and business customers.
And this doesn’t even begin to cover transmission. Currently, low transmission construction rates and low transfer capability between regions pose challenges to maintaining reliability and meeting the forecast power demand. For instance, in 2023, the U.S. only built 55 miles of high-capacity transmission. However, planned transmission expansion investments have increased to $15.1 billion for 2024, up from $9.2 billion two years prior. Still, this growth rate may not be substantial enough to match the demand growth rate. Insufficient transmission capacity to accommodate the flow of lowest cost electricity, often referred to as grid congestion, is a pressing concern as utilities are increasingly being forced to rely on more expensive sources of power to meet demand. The resulting costs are inevitably passed onto consumers who are already grappling with rapidly increasing electric bills.
As the demand for electricity surges, the power industry faces significant challenges in expanding infrastructure to meet these needs. The rapid growth in energy consumption forecasts underscores the urgency of addressing regulatory hurdles and financial burdens. In our next article, we will explore the impacts on ratepayers, examining creative buildout strategies and investments required to support this growth. We'll also consider the implications for decarbonization efforts and the evolving energy landscape. Stay tuned for a deeper dive into these critical issues.

2024 Was An Instrumental Year For Nuclear

Nuclear power appears to be in the midst of an unexpected revival that really took shape in 2024. This resurgence comes despite numerous plant closures since 2011 and the wildly high costs associated with projects like the Vogtle plant expansion we covered earlier this year, and it defied predictions from the post-Fukushima era.
Since 2011, approximately 12 U.S. nuclear power plants have been fully retired, with others scheduled for closure, according to the U.S. Energy Information Administration (EIA) and the Nuclear Regulatory Commission (NRC). These retirements were driven by a combination of safety concerns, economic challenges, and shifting energy policies. However, some plants previously slated for closure have remained online due to grid reliability concerns.
Certain nuclear facilities, such as the Diablo Canyon plant in California had license expirations scheduled for last month (Nov ‘24) and August 2025, respectively. Diablo Canyon, which provides 10% of California's electricity and about 30% of its carbon-free power, plays a crucial role in maintaining system reliability where viable alternatives have not been identified yet.
In contrast - the Indian Point Reactors 2 and 3 in New York were retired around 2020 after the state regulators discontinued issuing extensions. The deficit in downstate NY generation was mostly filled by natural gas-fired plants, a step backward from the State’s aggressive carbon reduction targets. New York’s carbon problems took another blow this month with the announced cancellation of the Clean Path project; look out for our next issue for more coverage.
Despite the challenges, new nuclear projects are emerging. The Vogtle 3 & 4 expansion in Georgia, with over $35 billion in construction and finance costs, became the most expensive power plant ever built, exceeding its budget by approximately $17 billion. This project highlights both the ambition and the financial risks associated with new nuclear development.

Source: EIA

There have been recent proposals however that aim to meet the growing energy demands of data centers using nuclear power. For instance, PPL Corp.'s amended agreement with Talen Energy Corp. would increase power supply from the Susquehanna Nuclear plant to an Amazon datacenter campus from 300 MW to 480 MW, demonstrating the potential synergy between nuclear power and the tech industry's energy needs.
In September, Microsoft announced a multi-billion dollar power purchase agreement with Constellation Energy, in which Constellation will recommission its reactor at 3 mile Island, which retired in 2019.
In another significant move, tech giant Meta issued an RFP earlier this month (Dec ‘24) to developers last week, seeking to add 1-4 GW of new nuclear generation capacity in the U.S., with delivery starting in the early 2030s. This initiative aligns with the growing interest in Small Modular Reactors (SMRs), which offer a promising solution for companies like Meta seeking to diversify their energy sources. SMRs are advanced nuclear reactors with a power capacity of up to 300 MW per unit, significantly smaller than conventional nuclear power plants. These compact, scalable designs can be factory-assembled and transported to sites for installation, potentially reducing construction times and costs.
With developments like these in 2024, what was looking like the beginning of the end for the nuclear industry may have actually just been the end of the beginning. 2025 could look very different though. There are only 1 of 2 remaining reactors that are currently offline and which could be candidates for resuscitation. The big news that could drop next year would be new orders or plans for new orders of additional reactors. In the words of Ella Fitzgerald, this could be the start of something big.

U.S. Solar Market Braces for Expansion Despite Short-Term Dips

2024 has been a record-breaking year for utility-scale solar installations in the United States with more than 32 gigawatts (GW) deployed across the country. The surge is partially driven by pent up demand after the expiry of the anti-circumvention tariff moratorium requiring modules to be operational by December.

Despite this year's achievements, the American Clean Power Association (ACP) predicts a temporary slowdown in 2025, with installations expected to decrease by 16% to around 27 GW. However, the long-term outlook remains positive, with projections indicating a rebound to 32 GW by 2027 and an increase to 34 GW by 2028. The ACP's new biannual Solar Market Monitor (in collaboration with S&P) forecasts a steady compound annual growth rate of 6.6% from 2025 to 2030, ultimately reaching 37 GW of annual installations by the end of the decade.
The incoming second Trump administration and a Republican-led Congress pose some uncertainty to the solar industry, especially with respect to proposed tariffs on imports and any possible changes to the IRA. The solar industry benefits from extension of the Investment Tax Credit, related bonus tax provisions, and changes to tax equity credits in subsequent IRS guidance. Industry views are somewhat mixed on what the new administration will bring but most agree that the IRA will remain in place due to Republican support in Congress. These particular provisions within the IRA may be relatively safe, but this is far from certain.
According to ACP, the levelized cost of electricity (LCOE) for utility-scale solar is currently at $46 per megawatt-hour (MWh) and is expected to decrease to $38/MWh by 2030. This decline is bolstered by the recent drop in polysilicon prices, although there is concern that new tariffs could reverse these gains by increasing capital costs.
Despite potential political uncertainties, the U.S. solar market's growth trajectory is supported by ongoing technological advancements and decreasing production costs. The collaboration between ACP and S&P aims to enhance understanding of the supply chain, technology, and demand dynamics, which will be crucial for navigating future market conditions, particularly during times of policy flux.

Understanding and Preparing for Winter Disruptions in Natural Gas Production

As we approach the new year and colder weather, it's important to revisit the challenges posed by winter storms on natural gas production. We offer some tips to manage your energy contracts through this risk.

Over the last few years, significant storms like Uri (2021), Elliott (2022), and Heather (2024) have underscored the vulnerability of our energy infrastructure, with disruptions impacting production by more than 15 billion cubic feet per day (Bcf/d) at their peak. These incidents, while temporary, stress the importance of preparedness and resilience in our energy systems.
The Permian Basin, a key region for U.S. natural gas production, experienced the most notable declines. Winter Storm Uri, for instance, saw nearly a 45% drop in production in Texas alone, highlighting the need for robust weatherization measures. Subsequently, Texas adopted the state’s first weatherization rule for natural gas facilities, aiming to secure gas flows to power generators during extreme weather events.
In the Northeast, including the Appalachian Basin, production declines are more pronounced due to frequent below-freezing temperatures. The introduction of additional weather-resistant equipment has been essential in mitigating production interruptions. However, despite best efforts, the nature of these disruptions—ranging from freeze-offs to power outages—means that some impact is inevitable.
To combat these challenges, industry players often employ several strategies:
- Chemical Injection: Injecting methanol or other chemicals into the natural gas stream can significantly lower the freezing point of water, reducing the risk of ice blockages.
- Infrastructure Enhancements: Enclosing compressors and machinery or installing pipe insulation with built-in heating cables can shield critical components from severe cold.
- Operational Adjustments: Proactive measures such as pre-emptive production suspensions before severe weather can prevent longer-term damages.
For our clients, the key takeaway as winter approaches is preparedness. Customers should review their emergency contacts for both utility personnel and operational staff within their organizations. This is especially important for clients on interruptible gas supply wherein the utility will notify designated contacts ahead of supply cutoffs and operational flow orders. Customers with spot market exposure should also be aware of daily market trends that may impact their cost of service, especially if they have price sensitive demand, dual fuel, and/or curtailment options. For budget priority customers, we recommend buyers be hedged for most of their fuel over the winter months. Review contracts to understand whether fuel is physically or financially contracted, and the definitions around firm or secondary gas supply obligations. Awareness of these core arrangements can help to mitigate the impacts of unforeseen price spikes or curtailments due to sudden supply shortages.

Market Data

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