Energy Markets

Is Coal Back in Vogue?

Written by Weekly Market Update | Apr 9, 2026 5:33:55 PM

Energy Markets Update

Editors Note: We ended last year expecting affordability to be a defining theme in 2026 and so far, events are falling into line. Frigid weather across large swaths of the US, geopolitical conflicts in Venezuela and Iran, and continued announcements on new data centers and their associated load growth have kept the prospect of rising energy costs in the media spotlight and the average American’s psyche.

A key fundamental we’re watching is an early-season indicator that 2026 could be among the driest years in the past 15, increasing the likelihood of a hotter summer, higher demand, and reduced hydro generation in major population zones in the South and West Coast. In several markets, the potential downstream effects have not yet fully emerged. This week, we dig into key trends in gas storage, coal generation, and the many risks in an increasingly chaotic world.

Table of Contents

Weekly Natural Gas Inventories

Source: EIA, Veolia

 

Energy Market Update

  • Energy historian Daniel Yergin famously stated "the market tends to forget the vulnerability of the Strait of Hormuz, treating the smooth flow of oil as a certainty rather than a precarious reality.” 
  • A two‑week ceasefire in the U.S. - Iran conflict on April 7 triggered a sharp drop in global oil prices, with June delivered Brent sliding about 13–18% to just under $98 per barrel from highs above $118 last month. WTI is trading at about an $8 discount. Now a month into the US-Iran war, Middle East supply disruptions continue to dominate headlines and ripple through global energy markets, despite recent news of a temporary ceasefire. The US has moved to stabilize the issue with temporary policy changes, but the damage has already been major. Brent crude oil and WTI are up over 50% since the crisis started.
  • April NYMEX settled at $3.095/MMBtu, marginally higher than March but well below February's settlement over $7/MMBtu. The prompt month is currently trading at $2.72/MMBtu – near term gas costs look soft. 
  • Our analysts are watching drought as a key near-term driver of power prices. Current data points to one of the driest years in roughly the past 15, which often coincides with a hotter summer. Drought in the West and Southwest can raise cooling-related electricity demand and cut hydropower output, forcing the grid to rely more on natural gas and lifting costs across multiple regions. 

 Source: Droughtmonitor.unl, 4/2/2026 

  • Gas storage levels remain healthy at roughly 5% above both the one year and five-year average. The upcoming months will prioritize building up inventories in preparation for next winter. There will be more coverage in our ‘26 injection season outlook below.
  • NYMEX prices for the remainder of 2026 are down 15% since last month. Calendar year 2027 has seen more modest declines of 5% while 2028 remains flat. This could be an opportunity to lock in prices before compounding risks of weather, drought, prolonged war, and who knows what else may emerge.


      Source: Veolia, Argus
  • Spring energy procurement season is underway — and that means budget planning is top of mind for many of our customers. Reach out to our expert team commodity@veolia.com to help you make the most of this season!

Notable Around the US:

Is Coal Back in Vogue?

  • In previous newsletters, we covered the DOE’s use of emergency orders to keep coal-fired power plants online past their scheduled retirement dates. Designed to address capacity shortfalls and prioritize domestic fossil fuel resources, these orders have piled up since they were first issued last May. As a result, US coal plant operators retired the least amount of capacity in a decade in 2025. This begs the question, is coal back in Vogue or will it go the way of shoulder pads and JNCO-style jeans?

  • According to S&P, roughly 3 GW of coal-fired capacity was retired in 2025, nearly 80% below initial forecasts and the slowest rate of decline in years. We’ve seen executive orders extend the operating lives of many large coal plants in 2026 and we expect this trend to continue in the short-term. As long as there’s concern about available capacity to meet increased data center demand, which is on track to more than double by 2030, there will continue to be support for maintaining the existing fleet of coal-fired plants.

  • Public opinion on fossil fuel versus renewable energy development is shifting as well. A recent Pew Research Center survey found that an increasing number of Americans support prioritizing fossil fuel development over renewables to address energy supply needs. This change was notable among both Democrats and Republicans, albeit more pronounced among Republican leaning individuals (see chart below).

Source: Pew Research Center 

  • So are we witnessing a comeback for coal? Not really. The reality is less promising. More than 60% of the coal-fired generation capacity that was operational in 2010 has either been retired or is slated for retirement by 2030. The remaining fleet is increasingly weighed down by aging infrastructure, ballooning maintenance costs, and environmental compliance costs that create high cost premiums compared to natural gas and renewables. Even if aging coal-fired plants stay in the market, their utilization rates are extremely low, only being dispatched a few days of the year when grid demand peaks. Combined-cycle gas generation and utility-scale solar can provide power at rates that are roughly 30% and 50% cheaper than coal, respectively. Even for new generation, the most recent Levelized Cost of Energy report from Lazard indicates that the cost of combined cycle gas plants and renewable wind and solar, even when coupled with batteries, is predominantly lower than the cost of new coal-fired plants.



     Source: Lazard, 2025 

  • The US coal fleet isn’t getting any younger either - no new coal-fired plants have entered service since 2013. Despite recent federal regulations aimed at supporting coal-fired power generation, utility companies and miners aren’t seeing price signals that encourage building new plants. Initiating new projects require significant capital investment and long-term contractual commitments and uncertainty surrounding long-term policy and a lack of new scalable technology are cited as the major reasons discouraging new construction. While coal may look like a reasonable temporary solution, the economics don’t support its long-term prospect.

  •  In the interim, it appears that ratepayers will likely continue to foot the bill to keep many coal-fired plants online past their planned retirement date, until they are relieved by newer gas-fired plants. The J.H. Campbell plant in Michigan, which has remained open following a DOE emergency order, is costing ratepayers over $600,000 per day according to the Wall Street Journal. Industry experts posit that the total cost to ratepayers across the country will be $3-$5 billion per year.  

Source: S&P 

  • We anticipate more jockeying between state and federal regulators and grid operators in the coming years as extensions are further scrutinized. When push comes to shove, they will need to find a solution that balances reliability with cost, and continued operation of coal-fired plants starts to weigh on cost at the expense of reliability. Although federal action may slow plant retirements for now, it is likely just delaying the inevitable. The average age of coal plants in the US is 44 years. Like many fashion trends that were born in the 80s, we don’t expect this one to come back in style. 

What the Injection Season Means for Winter 2026-27

As winter fades, the natural gas market shifts from withdrawal to injection season, crucial for shaping storage expectations and pricing for the upcoming winter. With strong starting inventories, we examine the effects of recent weather events, rising production, and expanding LNG exports on supply and demand. We weigh the potential influence of El Niño and its implications for cooling demand. The interplay between these factors will be crucial in shaping market volatility and risk heading into the winter of 2026-27.

  • The natural gas injection season outlook is critical as it shapes storage expectations and risk profile for the upcoming winter, which ultimately drives pricing, volatility and hedging decisions in gas markets.
  • At the start of winter 2025–26, natural gas storage was 92% full for the Lower 48 states, with all regions at or above 86%. Total gas inventories exceeded 3.9 Tcf, about the same level as last fall, and the highest since 2016.

Source: EIA

  • Despite strong starting inventories, early and severe winter weather rapidly depleted storage levels. Winter Storm Fern in late January drove record demand and erased the initial storage surplus through elevated withdrawals. By the end of the withdrawal season on April 1, inventories stabilized at ~1.9 Tcf, ~5% above the five-year average of 1.82 Tcf.

  • The EIA now forecasts storage to reach ~4.01 Tcf by October end, which would be above the five-year average of 3.76 Tcf. However, other analysts project a lower storage level averaging at 3.6 Tcf, indicating a tighter supply-demand balance. The following section outlines the key supply and demand drivers behind the end-of-season inventory outlook. 



 Source: EIA, Veolia 

  • On the supply side, U.S. dry natural gas production through March continued to outpace the same period in 2025, averaging ~2% higher. The EIA expects this trend to persist, with output rising from 107.7 Bcf/d in 2025 to ~109.6 Bcf/d in 2026 and ~112.6 Bcf/d in 2027. Growth is expected to be driven by the Haynesville, Permian, and Appalachia regions. In Permian, higher oil prices and rising gas-to-oil ratios are supporting increased oil-directed drilling, boosting associated gas supply, while in Haynesville, drilling activity has exceeded prior expectations, further strengthening production growth. 

 Source: EIA, Veolia 

  • On the demand side, LNG export capacity is set to expand in 2026 with Corpus Christi Stage 3 (Train 5) and Golden Pass Train 1. LNG export capacity is projected to increase from ~17 Bcf/d at the end of 2025 to over 19 Bcf/d in 2026. This incremental demand will absorb a portion of domestic production and limit potential storage builds. 
  • Another wild card is the summer weather outlook, which could increase sensitivity to demand swings. According to NOAA, there is a 62% probability of El Niño weather pattern this summer and persisting through year end. A strong El Niño would boost average global temperatures in 2026, increasing cooling demand and gas-fired power burns. This incremental demand along with growing LNG exports could offset supply growth, tightening the gas storage trajectory and resulting in a thinner cushion heading into the winter of 2026-2027, ultimately increasing the market’s exposure to price volatility. 
  • The interplay between production growth, LNG-driven demand, and weather patterns will be critical in shaping market conditions and risk heading into the 2026-27 winter. Veolia supports its customers by providing market insights, scenario analysis, and tailored hedging strategies to help navigate evolving dynamics, manage exposure to volatility, and optimize long-term energy costs. 

 

 The Deal That Swapped American Wind for Global Gas

The U.S. offshore wind industry has been a consistent target of the Trump Administration’s policy shifting away from clean energy and towards traditional fossil fuel projects. There has been a constant drip of setbacks for the sector, including federal permitting freezes, the early sunsetting of tax credits, stop-work orders, and ongoing legal battles. Into that unsettled landscape, a recent agreement has raised even the heaviest of eyebrows. 

  • In late March 2025, The US DOI agreed to reimburse TotalEnergies ~$928 million, offsetting the full lease costs the company paid for sites off the coast of New York and North Carolina removing ~4GW of electricity supply from the US. In exchange, TotalEnergies pledged to invest the reimbursement into further development of the Rio Grande LNG export terminal in Texas and expanded oil and gas operations along the Gulf Coast.

Source: TotalEnergies Offshore Wind Portfolio 

  • TotalEnergies' CEO has publicly suggested that other offshore wind developers may pursue similar arrangements. If that proves accurate, the deal could represent the beginning of a broader unwinding of the U.S. offshore wind development pipeline, putting in jeopardy more than 9.8 GW of pending power supply on the eastern seaboard alone.
  • The financial mechanics of the deal are not straightforward and the standard practice for energy infrastructure leases has been that auction proceeds, once paid, belong to the federal government. For context, when Royal Dutch Shell walked away from $2.1 billion in Alaskan oil and gas leases in 2016, receiving no refund.  
  • When companies win offshore lease auctions, those proceeds flow directly to the U.S. Treasury and become part of the federal budget. There is no standard mechanism for the DOI’s Bureau of Ocean Energy Management (BOEM) to issue refunds of this scale with the agency's 2026 budget amounting to only $148 million, a fraction of the reimbursement amount. 
  • The question on the source of these funds, TotalEnergies’ description of the deal as a “settlement”, the involvement of the US Attorney General in the announcement suggests the payment may be routed through the Justice Department's Judgment Fund, a pool of taxpayer money used to resolve legal claims against federal agencies. 
  • TotalEnergies has committed the reimbursed funds to projects like the Rio Grande LNG terminal in Texas, infrastructure designed to export liquefied natural gas to overseas markets rather than lower energy costs for American consumers. With US LNG export capacity peaking at 18 bcf/d in 2025, the chart below makes clear that this investment serves foreign demand, not domestic energy needs. 

Source:  US Energy Information Administration  
  • Offshore wind, by contrast, was designed to add electricity directly to domestic regional grids, adding to our power supply in constrained regions without creating additional exposure to volatile fuel prices.
  • The U.S. has issued roughly 40 offshore wind leases since 2012. Only eight projects have reached the construction phase. The TotalEnergies deal, if it becomes a template, could significantly reduce that number further.
  • The TotalEnergies agreement highlights the risks changing federal priorities have for energy development and specifically for regions of the United States that are relying on offshore wind as a core generation source. If this arrangement becomes a template, the offshore wind pipeline could be systematically unwound through a series of similar financial agreements, eroding a domestic energy supply for power-constrained regions along the eastern seaboard.

 

 

Market Data

 

 

 

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