Energy Markets Update

In this newsletter, we cover key factors impacting US energy markets.  We report on our current power standing as we enter the spring shoulder month, important updates to capacity markets, and how tech companies are influencing the energy world. 

Table of Contents

• Gas and Power Update
• Shoulders and Shrugs
• Capacity Markets From East to West
• How Tech Companies are Shaking up the Energy Business

Weekly Natural Gas Inventories

Source: EIA

Source: EIA

Gas and Power Update

• NYMEX gas has trended downward over the past 2 weeks, but not without significant daily volatility. On Friday, the April NYMEX contract settled at $3.98/MMbtu following a $0.27 drop from the day prior; a selloff that has continued this week despite an attempted rally on Wednesday wherein prices ultimately retreated from the crucial $4 mark. Prompt month NYMEX settled at $3.84/MMbtu yesterday but the Summer 2025 strip is still trading at $4.30 and the highwater mark remains the Jan 2026 contract at $5.30 per MMbtu. The Summer trade will be fascinating to watch as it is fragile, and very much tied to the sentiment further out in the strip.
• Short-term weather forecasts support recent bearish momentum as above average temperatures are anticipated for the coming 11-15 days, particularly across the southern and eastern US. This is a stark reversal from last month – which incurred 20% more heating degree days compared to February 2024. The combination of a frigid arctic air mass descending mid-month and persisting La Nina conditions caused temperatures in some parts of the country to plummet 50 degrees below average.
  Source: S&P Global
• Despite the recent sell-off, overall the NYMEX has found significant and enduring support over the last 3 months, led by colder seasonal temperatures coupled with bullish fundamentals like the anticipated increase in LNG exports next year. Prices in 2025/26 remain significantly higher compared to the outer years. Calendar year 2026 is currently sitting at $4.38/MMbtu (~12% higher than Cal'27).
• Wholesale power prices have declined across most regions and particularly in New England, which experienced average February spot prices of $126.40/MWh (up 305% year-over-year).
• Wholesale Electricity Monthly View: ISO-New England
  
  
  Source: ISO New England
• While the most volatile period of winter index exposure is over as we (finally, and with open arms) welcome Spring, the price for both gas and power will be materially higher this year with all eyes on 2026 in particular.
• Capex for energy utilities in 2025 is forecasted to surpass 2024 spending by a staggering 22% (a difference of ~$39 Billion) according to a recent S&P report. We’ve previously covered some of the driving factors of this investment need – replacing aged infrastructure, constructing new gas and renewable generation capacities, and addressing ever-growing demand, to name a few.

• Coal-fired power production during Q1 (Jan-March) has been 21% higher year-over-year. This uptick has been influenced by the rally in NYMEX prices – We take a deeper look in the next article at what this could mean for gas prices for the rest of the spring into summer.
• On March 20th, the DPS, NYSERDA, and DHSES responded to Senator Schumer and Governor Hochul’s letter demanding a review of the potential impact of tariffs by the Trump Administration and a US/Canada trade war. Their report highlighted the difficulty of forecasting price impacts given all of the uncertainty – which is being experienced by grid operators, suppliers, and energy consumers alike. They also pointed to concerns about Canada's threats to halt imports to New York, which has the potential to create serious reliability issues in NYISO.

Shoulders and Shrugs

The 2025 spring shoulder season has a few market-moving variables that are set to influence energy price trajectories through the rest of the year and likely into the next. We’re looking at this spring’s specific seasonal vulnerabilities (nuclear downtime), the deficits the US and its largest LNG buyers face with respect to gas in storage, and the strategic dance of gas-to-coal switching as power generators navigate supply costs.

• Spring has sprung, and another shoulder season is officially underway! Our industry uses the trading terminology for the months of March to May as one of the two shoulder seasons between winter and summer when energy demand and wholesale prices traditionally are lowest driven down as buildings in the US require less heating and cooling (see Fixed Power Forward Curve for Zone J (NYC) illustrating the head and shoulder trading pattern below). Often, shoulder seasons mark an inflection point in markets as traders take stock of underlying fundamentals, uninfluenced by short-term weather trends.

• This year's shoulder months are generating more market uncertainty than usual. While these transitional periods typically follow predictable patterns, several key factors are making analysts question what comes next.

NYC’s Forward Power Curve In The Head And Shoulders Pattern

Source: Argus, 3.26.2026

• A critical but often overlooked factor during this lower-demand period is that it's also nuclear plant maintenance season. For example, the Southeast currently faces significant planned nuclear outages, putting traders on high alert for above-normal spring temperatures that could trigger increased gas-fired generation demand. The chart below shows the total outages last week on March 18 were north of 14,000 MW, totaling ~14% of the nation’s total nuclear generation capacity (see map below). The back of the envelope projection, according to Constellation Energy, for the additional natural gas required to cover the difference of 2.82 BCF a day of gas generation.

US Nuclear Power Offline for Maintenance, March 18, 2025

Source: Constellation, Gridstatus.io

• While US demand is consuming additional gas to cover for nuclear deficits, and balance the current domestic requirements, it's also working this spring to rebuild depleted inventories. Winter withdrawals exceeded industry forecasts, leaving US storage levels well below expectations. Compounding this challenge, the EU - America's primary LNG customer - faces similar inventory deficits, intensifying competition for available supply (see high level storage level comparisons March 24-  March 2025)

• The US and EU require additional natural gas storage and reception capacity exceeding 5 BCF per day above existing demand levels. The EU has set a deadline of November 1, 2025, and demonstrates readiness to pay premium prices for LNG compared to US market rates. The critical uncertainty lies in whether US production can expand sufficiently to meet these heightened requirements, particularly considering current demand growth driven by increased data center operations and the growing number of LNG shipments bound for other markets like Asia. So far in 2025, US production is up by about 3 BCF/d year-over-year.
• Last is the wild card of the strategic dance of gas-to-coal switching as power generators optimize for the lowest generation cost based on marginal fuel inputs. As we noted already - coal fired power consumption is already up 21% in Q1 2025 compared to the same quarter last year. Assessing what this could inform us of for the rest of the year and the implications, we can look at 2022 as a recent example.
• 2022 coal consumption for electricity generation reached 473,000 tons as power plants favored the relatively cheaper coal option to gas which averaged $6.64/MMBtu for the year. The course changed again in 2023 as natural gas prices dropped below $3/MMBtu, causing coal consumption to decline 18% to 387,000 tons, reinforcing the direct relationship between fuel prices and generation choices.
• The key threshold price of $4/MMBtu, identified by Constellation Energy, represents the levelized cost point where natural gas and coal reach parity (reference our technical diagram below).

• As power plant owners and operators consider their fuel choices for this spring and into the summer, they will also evaluate several factors beyond this $4/MMBtu benchmark, including plant retrofit costs, downtime requirements for fuel switching, environmental compliance expenses, and the expected duration of current natural gas pricing trends. These decisions become particularly critical as plants must determine whether current low natural gas prices represent a sustainable trend that justifies potential infrastructure investments and operational changes. And therein lies the wild card.
• If you’ve been doing the math at home for what the natural gas supply/demand balance may look like come June, it might be looking something like:
  
  -   Nuclear generation maintenance  (Avg 1-3 BCF / day March - May)
  -   Necessary US and EU gas replenishments (2-5 BCF / day)
  -   Anticipated LNG exports (~2+ BCF/d higher)
  +  March 2025 daily domestic production (+3bcf year over year)
  +  Coal substitutions announced for this summer (Wild Card) 
  _________________________________________________________
       =  The Shoulder Month Shrug

Capacity Markets From East to West

• Stakeholders Say “Not-So-Fast” on Proposed Price Cap and Floor in PJM As reported in our January 30th newsletter release, PJM has proposed a tentative plan to set a price ceiling and floor to the capacity auctions for the 2026/2027 and 2027/2028 delivery years. Originally proposed by Pennsylvania governor Josh Shapiro, the aim of this “price collar” is to avoid a sky-high clearing price as seen in the 2025/2026 auction. To put it into perspective, some predict clearing prices over the next few delivery years to average around the clearing prices seen in the 2025/2026 auction - highlighting concerns that high capacity prices are here to stay.
• Since our initial reporting, comments filed at FERC by several parties reveal concerns with the proposed price collar - specifically, that the price floor of $175/MW-day is still too high for ratepayers and undermines the purpose of having an open capacity auction in the first place. Theoretically, in an open auction prices could clear at prices in the double digit range - which would be a much welcome price relief to PJM ratepayers only in the absence of a price floor. Adding conditions to the definition of an “open market” risk that ratepayers will foot the bill for capacity upgrades that are either available at a lower price and/or don’t actually materialize.
• PJM asserts that the proposed price floor covers the risk that investors in generating resources take on, ensuring that they will receive at least a minimum amount of revenue to offset the risks of having a price cap. The proposed price floor is higher than the average of all previous capacity market weighted average auction clearing prices of $116.30/MW-day (excluding the most recent auction anomaly).
  We will continue to report as the proposed changes move through the FERC approval pipeline. PJM requested an effective day for the proposal on March 31, 2025.
  
  
• Updates on ISO-NE Capacity Market Facelift At its March 1st meeting, the NEPOOL Markets Committee touched on the status of the ongoing ICAP market study, which is evaluating the effectiveness of the Installed Capacity Requirement (ICAP) market in ensuring long-term resource adequacy.
• The study is expected to be completed later this year and will inform potential market design changes.
• To recap, the proposed market changes on the table in ISO-NE include delaying the 19th capacity auction, introducing prompt/seasonal capacity auctions, increasing participant collateral requirements, and changing the process for generators to signal intended retirements. This is a dramatic departure from the 3-year ahead forward capacity market design in New England that has been in place since 2006.
  
  
• Dusting off Resource Adequacy in CAISO While there has not been much news on CAISO’s resource adequacy market, we have found that at a high level, load-serving entities in CAISO appear better hedged against resource adequacy price spikes than initially projected when market reforms were finalized last year, resulting in lower realized rates in 2025 vs 2024.
• California is transitioning from its seasonal peak resource adequacy market to an hourly “slice of day” requirement this year – all load serving entities will need to demonstrate resource portfolios that meet the demands of their customers in all hours of the day.  
• We will continue to monitor changes in the CAISO RA market and advise clients accordingly.

How tech companies are shaking up the energy business

The ever-increasing demand from rapidly expanding datacenters is causing ripples throughout all facets of the energy sector, from supply availability, to price volatility, to cost allocation. 

Tech giants’ giant investments.
Large datacenters currently rely on a mix of fossil fuels and alternative power sources already on the grid, but there isn’t enough power to meet their growing demand over the coming years. Tech companies are increasingly making direct investments in energy infrastructure.  

• At the moment, xAI’s supercomputer in Memphis is being powered largely by dozens of gas turbines and Tesla megapacks. The project has doubled in just a few months, so much of the additional power supplies are temporary until permanent resources are built, like their planned substation and wastewater treatment facility.  
• Late last year, Microsoft struck a deal with Constellation reviving its retired nuclear reactor at Three Mile Island. Constellation says the reactor could be running again by 2028, and Microsoft will purchase the entire output with a long term power purchase agreement, roughly enough energy to power 800,000 homes every year. 

Source: S&P Global

Cost Allocation Issues
As large tech companies search for more power to provide for their datacenters, some of the stresses on the bulk power system make their way into general utility bills for other ratepayers. 

• A Harvard University paper recently pointed out that utilities can embed costs related to the data-centers’ increasing demand into residential rates. This may be through explicitly discounts provided to incentivize datacenters or more generic rate design approaches that shift costs away from data-center owners
• PJM’s $5.1 billion regional transmission expansion plan received criticism from the Maryland Office of People’s Counsel for unjustly charging Maryland residents for transmission upgrades needed to accommodate datacenters growth in Northern Virginia, a growing hotspot for some of the largest projects. The plan was ultimately approved by the FERC.
• Another threat involves colocation: increasingly,  datacenters are being constructed adjacent to a nearby generator with which they enter into a direct power purchase agreement (oftentimes with inexpensive nuclear energy). There is some precedent for these types of arrangements to permit the bypass of the regional distribution and transmission system, as it is argued very simply that if these facilities are not used, they need not be paid for. The issue however, is that those power resources are withdrawn from the wholesale power market and the higher marginal costs of generation and transmission are borne by other customers.
• FERC has recently committed to providing quick and clear guidance on a slew of  questions presented by PJM.
• The Harvard study  listed four recommendations to protect consumers from these hidden costs: 

1. State regulators should establish more rigorous guidelines for reviewing special contracts. While these issues can stem from utilities aiming for competitive prices for datacenter owners, often they can arise from a subpar vetting process of these contracts. 
2. State regulators could require utilities to offer standardized terms and conditions for future datacenter customers.
3. State legislators could require datacenter customers to contract with competitive power suppliers.
4. The creation of state-approved "energy parks," where sufficient on-site generation is available to power large datacenter operations.

• Many gas utilities across the Mid Atlantic and South are increasingly pursuing partnerships with datacenters as a means to backstop new growth.  
• Conflicts such as regional pipeline constraints, and some government organizations are considering expanding pipeline infrastructure to be able to meet demand for these projects. To date, most of the reporting and analysis of data center expansion has been on the strains that growth will have on the power sector. As gas-fired generation continues to support new growth, the next frontier of data center constraints could be in the pipeline.
• In Texas, various large developers are seeking long term natural gas contracts for baseload power. Other companies, such as Northwest Gas Co., have received inquiries in the Northwest US, but regional pipeline constraints may make that difficult. The Arizona Corporation Commission is exploring expanding natural gas pipeline infrastructure to satisfy baseload demand for the grid and anticipated datacenters.
• Similar conversations are being had in virtually all regions of the US. 

Market Data

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