2025: Stress, Shifts, Signals

Energy Markets Update

Editor’s Note:  As we draw 2025 to a close, the Energy Markets team at Veolia reflects on a whirlwind year that really does feel like a stage-setter for major shifts ahead. Some of the major themes on our mind and the focus of this newsletter are the immense challenges in interconnecting large new datacenter loads, the rapid expansion of the US LNG export machine, and shifting federal priorities from renewables to traditional infrastructure. Most of these trends have long been anticipated. Most are all still in relative infancy. However, they are all poised for rapid acceleration in 2026 and 2027. We see a period ahead characterized by environmental challenges, growing delivery constraints, larger price swings, and an increased reliance on flexible energy resources. This will be a challenging period.

At a corporate level, we believe we are taking the right steps. Towards the middle of 2025, we closed on the purchase of Icetec, a specialized demand response provider that will enhance our flexible energy capabilities. Just recently, Veolia announced the purchase of Clean Earth, making Veolia a market leader in the US hazardous waste and recycling industry. This merger unites two of the largest hazardous waste networks in the USA, adding ~1,790 employees across 80 facilities to Veolia’s team.

Our Energy Markets team added three new staff this year: Nate Ryan, Nick Keohan, and Kinnery Mehta. All have diverse skills, ranging from renewable energy analytics to market expertise to bill auditing and energy modeling. We expanded our clean energy markets coverage this year and we enhanced many of the digital tools on our Hubgrade energy management platform. We also bid farewell to our exiting intern Dylan Sabenfass, who returns to Northeastern University with a newfound passion for energy markets and sustainability. Thank you for reading, and see you in the new year! 

Table of Contents

• Energy Market Update
• 2025 Was A Year of Stress Tests and Recalibrations
• Winter's Early Punch: What the 2025-2026 Outlook Means for Gas Markets
• Q&A with the Flexible Energy Group
  

Weekly Natural Gas Inventories

Source: EIA

Energy Market Update

• With the coldest start to December in over a decade, the NYMEX prompt month gas contract has been a focal point of energy market volatility, reaching a three-year high of nearly $5.50/MMBtu in the first week of December before dropping to $4.02/MMBtu, shedding ~27% of its gain in a matter of days.
• The 2026 calendar year strip settled at $3.76/MMBtu yesterday, a 15% drop from its peak on December 5th; while future years 2027 & 2028 saw 5% and 2% drops respectively.
• After posting the first three withdrawals of the season, all less than 15 Bcf and well below normal for this time of year, the EIA reported withdrawals of 177 Bcf for the week ending December 5 and 167 Bcf for the week ending December 12. The above-average withdrawals in the last two weeks are pushing storage levels down to about 1% above the 5-year average.
• Weather is now the moderating influence, driving an impressive rally in early December and then a sharp selloff on the heels of NOAA’s 8-14 day outlook (below). A quick return to $5.00 gas seems likely if January surprises with colder-than average forecasts.
• We’ve covered the major themes driving market uncertainty in depth. The US is approaching a structural shift, with roughly 20% of daily production slated for LNG exports by the middle of next year. Production, now approaching 110 Bcf/d, has continued to grow but is quickly being swallowed up by rising LNG feedgas. Golden Pass LNG appears to be cruising ahead towards commercial operation early next year. Train 1 of this project is expected to pull about 0.8 Bcf/d of its 2.5 Bcf/d full capacity. The 3 trains will be gradually rolled out throughout 2026, increasing U.S. LNG exports by ~15% by the end of the year.
• Spot power rates surged in New England and New York over the first two weeks of December, with Boston LMPs approaching $170 per MWh. Warmer temps should soften prices for the remainder of the month.

• Forward market premiums still exceed 40% across most regions, except for the West. Some of the biggest declines have been in PJM east where prices have shed about 10% over the past week, returning to levels not seen since early October. 

In other news:

• PJM finalized results of its BRA capacity auction this week. The clearing price for the June 2027 to May 2028 period again cleared at the auction cap of $333.44/MW-day across the entire region. Despite procuring 11,299 MW of new resources and 145,777 MW overall, PJM notes that was 6,623 MW short of its target, eating into its reserve margin. The auction results put PJM in a tough spot as administrative design decisions, delayed and then accelerated auction schedules, and massive interconnection backlogs have inevitably contributed to higher prices for consumers. It is going to take some heavy handedness to pull PJM out of its current capacity mess.
• This week FERC directed PJM to develop new rules within 90 days for connecting AI data centers and other large loads to the power grid, including clear criteria for determining when large users can connect directly to power plants versus through the transmission system to ensure fair cost allocation. The ruling also requires PJM to create an interruptible transmission tariff option that would allow large energy users to accept potential service interruptions in exchange for faster grid connections, addressing the urgent demand from data centers while maintaining grid reliability.
• Earlier this month, FERC approved PJM Interconnection’s proposal to shed its governance over distribution-level generator interconnections. The change will become effective in April and it should allow for much faster interconnections of smaller generation projects while freeing up PJM staff to focus on transmission-level projects.  
• WTI oil dropped to about $55 per barrel this past week, a threshold not passed since early 2023.
• The Bureau of Ocean Energy Management moved to revoke the final construction permits for New England Wind 1 and 2, which were anticipated to begin construction in 2025 and commence service in 2029. The projects are estimated to provide 791 MW and 1,000 MW of generating capacity, respectively, but are now in jeopardy.
• A new state law in Connecticut reduces the Renewable Portfolio Standard (RPS) obligation starting in 2026, thereby lowering supply costs. Customers with supply agreements in place before July 1, 2025, can expect their 2026 supply rate to decrease by approximately $0.0032/kWh (~3% of total supply cost). This cost reduction is a direct result of the RPS Class I obligation decreasing from 32% to 25% in 2026.
  
  

2025 Was a Year of Stress Tests & Recalibrations 

What once lived in regulatory filings and RTO dockets made its way into earnings calls, front pages, and household bills. Throughout the year, our coverage followed one central thread: a grid under pressure to adapt fast to AI-driven demand, shifting federal policy, financial strain, and growing reliability risks. It was the year energy markets became impossible to ignore. 

Grid Reliability broke through the noise. PJM and MISO’s record-high capacity prices—approximately $330/MW-day and $666/MW-day—sent customer bills up double digits and signaled a deeper structural imbalance: retirements are accelerating faster than new supply can get built, while datacenter-driven load keeps surging. PJM’s auction results published just this week (see below), again cleared at the administrative cap and will ensure upward pressure on regional costs through at least mid 2028.
 

Source: PJM

• Across regions, the warning lights stayed on. We tracked New York City’s projected 4–10% capacity gaps, New England’s extension of aging peaker plants, and PJM’s 72 GW interconnection backlog, repeatedly delaying thermal retirements. The gulf between planning assumptions and physical system limits became impossible to ignore, causing the electricity market to flash price signals requesting additional supply.
• Battery storage was the rare bright spot. Utility-scale installations increased by 11.5 GW, a 44% increase in capacity from 2024. Storage quietly became indispensable in CAISO and ERCOT and remained one of the few clean-energy segments largely insulated from political reversals. However, storage's ability to stabilize electricity prices or curb emissions remains dependent on how these systems are optimized to dispatch generation, an evolving story for 2026.

These capacity shortfalls and price spikes didn't emerge in a vacuum. Behind the supply crunch was a rapid ballooning of demand that fundamentally reshaped grid planning assumptions. . While the magnitude of this demand growth ranges (we were introduced to the concept of vaporwatts this year), their profound impact on grid planning really came into focus in 2025.

AI-Driven Demand Growth moved from storyline to stress point. Datacenter load is now expected to nearly triple by 2030, reaching ~14% of US electricity use. Our reporting followed the ripple effects: congested interconnection queues, utilities revising rate structures, and new requirements forcing hyperscale customers to shoulder grid-upgrade costs or provide demand response. The central question became unavoidable: who pays for AI’s power boom?

• Nuclear, long stuck in “renaissance” purgatory, finally found commercial traction in 2025. We covered Meta and Microsoft’s long-term deals with Constellation, including power from Clinton and Three Mile Island, as well as revived US-Japan cooperation and the $80B Brookfield-Cameco-Westinghouse alliance. We watched Constellation Energy’s stock’s stock moon from $50 to $350 per share. For many policymakers, nuclear re-emerged as the firm backbone of an AI-era grid.
  
  
  
  

Source: S&P

As data center load projections rose and nuclear deals proliferated, the policy landscape that had enabled clean energy expansion began to fracture. What started as a technical challenge, matching supply to surging demand, quickly became a political one.

Regulatory Shifts and Federal policy whiplash defined the year. The Trump administration moved quickly to unwind core Biden-era climate programs—targeting EPA’s GHG Reporting Program, freezing or slowing major offshore wind projects, cutting DOE clean-energy funding, and advancing faster ITC/PTC phase-outs through the “One Big Beautiful Bill”- while focusing heavily on the development of traditional sources of energy in pursuit of U.S. energy independence.

• States recalibrated, too. Arizona repealed its RPS, New York deferred its 2040/2050 zero-emissions mandates, Massachusetts and Connecticut slowed RPS growth, and Pennsylvania floated a break with PJM over cost pressures. The through-line: climate ambition reframed around ratepayer tolerance and reliability risk.
• Trade and supply chain policy added more friction. New US tariffs on steel, aluminum, batteries, and solar components raised project costs by 10–20%+, while China’s export controls and FEOC rules forced last-minute supply-chain overhauls. Many projects were repriced or simply paused.
• On the gas side, record LNG exports - 15.7 Bcf - pulled US prices into a tighter global orbit, keeping domestic gas in the $3.50–$5/Dth range and steering drilling toward gas-rich basins like the Haynesville.

Source: EIA

The fault lines are now clear: AI-driven load growth, the durability of nuclear and storage, states balancing affordability with climate pacing, and federal policy swinging hard in new directions. As we move into 2026, the biggest questions - who pays, who decides, and what gets built - will shape every story we cover. We look forward to reporting the next chapter of this rapidly shifting energy landscape.

Winter's Early Punch: What the 2025-2026 Outlook Means for Gas Markets 

Winter arrived early this year, and the natural gas market reacted fast. Prices climbed toward three-year highs even as Lower-48 production remained historically strong and storage sat comfortably above the five-year average. As highlighted in the Energy Market Update above, prompt-month NYMEX contracts briefly pushed above $5.50/MMBtu on early-season cold risk.

More recently, warmer weather moving in mid-month has triggered a pullback in futures, reinforcing a key theme of this winter so far: price action is being driven less by fundamentals and more by weather risk. NOAA’s outlook is still crucial - but how traders interpret its uncertainty may matter more.

What NOAA is Calling for This Winter

NOAA’s December-February outlook (NOAA CPC Season Outlook) continues to reflect a classic La Niña setup: warmer-than-normal temperatures favored across the South and Mid-Atlantic, and elevated cold risk concentrated in the Upper Midwest and portions of the Northeast. That broad pattern has largely held so far.

Source: NOAA

Early December delivered worse and more widespread cold across northern demand centers than many November forecasts suggested, tightening balances and supporting the early rally. However, updated 8-14 day outlooks now point to a notable warm push developing mid-month, which has taken some immediate pressure off heating demand and helped drive the recent NYMEX sell-off as shown in the NYMEX 2026 future pricing chart below.

NYMEX 2026 Forward Pricing Chart

Source: Veolia

How Accurate Has NOAA Been: This Season and Historically?

So far this winter, NOAA’s models have been directionally correct but conservative on intensity. Early December cold materialized broadly across northern demand centers, consistent with NOAA’s seasonal outlook, though the magnitude of that cold exceeded what many November forecasts implied.


Source: NOAA

That pattern is not unusual historically. According to NOAA’s CPC verification studies, winter outlooks correctly identify broad warm versus cold regions roughly 60-75% of the time, but precision weakens when forecasting the strength and duration of cold events, particularly beyond a two-to-three week horizon.

La Niña winters add another layer of uncertainty. In past La Niña years, NOAA has tended to understate the risk of sharp, episodic cold in the Midwest and Northeast, where polar jet intrusions can develop quickly and drive outsized heating demand. As a result, markets often price a higher “tail risk” premium even when the baseline forecast looks manageable.

In short, NOAA’s outlook has been good at setting the map - but less reliable at defining the ceiling. That asymmetry helps explain why natural gas markets remain sensitive to January cold risk, even as near-term forecasts soften.

Why Strong Supply Hasn’t Kept Prices in Check

As noted in the Energy Market Update above, the recent price move has not been driven by supply losses or outright shortage risk. Instead, weather timing has amplified otherwise manageable fundamentals.

Key factors at play:

• Production remains near record highs, though recent daily data suggests growth is flattening rather than accelerating.
• LNG feedgas demand remains firm, keeping balances tighter than storage levels alone would imply.
• Storage is above the five-year average, but not high enough to fully absorb repeated or deep cold events.
• Early-season cold arrived sooner than expected, erasing the “mild December” buffer embedded in many November outlooks.

Together, these dynamics explain why front-month contracts have moved more aggressively than back months. The market is pricing near-term weather exposure, not a structural supply deficit.

Reconciling the Market Weather: Weather Risk Takes the Lead

This winter, natural gas pricing has been driven more by forecast uncertainty than balance-sheet math. NOAA’s early-season verification, combined with La Niña volatility, has kept traders defensively positioned.

What’s shaping market behavior:

• La Niña winters favor episodic cold, increasing the probability of sharp demand spikes even when baseline forecasts soften.
• January remains the key risk window, particularly for the Midwest and Northeast, where peak-day demand escalates quickly.
• Speculative positioning is concentrated in winter and early-spring expiries, not outer years, reinforcing the near-term focus.

In simple terms, the market is reacting less to what inventories say today and more to what the weather could deliver over the next few weeks.

What to Watch Next: The January Wild Card

Between now and February, price direction will hinge on a narrow set of variables:

• Storm tracks into the Midwest and Northeast
• Whether production stabilizes or begins to roll over
• LNG feedgas flows, especially if global prices stay firm
• Late-January pattern shifts, a recurring La Niña feature

If January runs colder than NOAA’s baseline, today’s risk premium may hold. If warmth dominates, the market could continue to retrace as weather-driven length unwinds.

Bottom Line

Strong supply has not been enough to offset early winter weather risk. For now, natural gas prices are reflecting concern over future cold rather than present scarcity. The next few weeks will determine whether that concern fades or sharpens as the heart of winter approaches.

Q&A with the Flexible Energy Group

Earlier this year, VNA made a strategic play to bring in new demand response capabilities through a 15-person team based in Philadelphia called Icetec (now integrated as Veolia Flexible Energy Services). The following is a recent discussion with one of our  new teammates, John Webster, who lives and breathes demand response.

1. John, thanks for taking the time to talk with us - it’s now December 2025, a year ago Icetec was independently operating, and now you are a part of our team. What are some of the changes that you’ve observed since coming on board, besides the big Veolia signs in the office and on the coffee mugs?
   
   "A few things stood out to me. First, lots of Celtics fans…jk. From a Business Development perspective, I noticed that we’re targeting the same organizations at different levels. When having prospective conversations with utility and plant managers at a site, we’ve learned that Veolia already has a strong relationship with the customer at the national/global level. This really leaves a positive impression when folks at the local level ask their global team about a brand they’re already working with.
   
   When we think about the growth in scale and geographic spread of emerging markets, we see joining Veolia as a great opportunity to attack these markets. We need a collective that understands the risk and opportunity, and our group’s ability to speak to and mitigate those risks was obviously limited before. Now, as part of a global brand, there is a totally different dynamic to those discussions, to how our technology solution might fit into an aggressive growth strategy."
   
   
2. We saw a video about your work with MIT with your dashboards displayed in one of our command centers in the Boston office - can you tell us more about that project?
   
   "MIT is such a great client. They have a state-of-the-art central utility plant, and we provide guidance on the most efficient and economic ways to operate it through our Human Machine Interface (HMI) software tool. The operators follow the guidance provided by HMI, and we’re able to monetize their operational flexibility in the ISO-NE Markets.
   
   Over the past 15 years, working with MIT, the scope and stakeholders have expanded. We also support them through our Carbon + Energy (CEP) platform, which has become the central carbon data repository and reporting tool for their compliance with BUEDO. It’s a great example of a customer that recognizes our ability to help with any of their energy problems, and the fact that we send them a big check every month rather than a big invoice helps too."
   
   
3. It sounds like you’re in demand in the Boston area (haha). Are there other universities, manufacturing campuses, or regions where you see the most potential for growth in 2026?
   
   "Yes indeed, we have several efforts underway to expand the geography where we offer flex market services – including in the MISO and ERCOT markets. We’re trying to cross-analyze or thread the needle, really, between areas that have the most opportunity with specific customer relationships or projects that need optimization. This process is underway, both evaluating existing Con Ops / Muni Water sites as well as with new leads that include energy flexibility, central utility plants, or frankly just industrial customers experiencing sticker shock from their utility bills."
   
   
4. As we’re seeing increased datacenter activity and changes in production, where can flexible energy provide the most relief? Where are we heading in terms of datacenter demand? Are there any projections you’ve been referencing?
   
   "We see this as a huge opportunity and an area where we can differentiate ourselves. Most of our customers are complex grid edge energy systems that might look like a generator, a large load, or a demand response resource depending on the weather and time of year, and data centers fit perfectly into this category. These sites are super complicated to optimize correctly, and that's exactly what our technology is built to solve: helping loads with excess generation decide whether to operate as a large consumer or a generator based on grid conditions and incentives.
   
   This is exciting because we have the technology to add value in this market, and joining Veolia provides the size, scale, and financial backing that puts our team in a better position to ride the data center / flexibility wave."
   
   
5. Give it to us straight - if we wanted to invest some time and money upgrading operations to include an onsite battery, what are going to be the easiest/hardest parts, and where do we start?
   
   "A lack of technical expertise on both the customer and vendor sides can pose the biggest challenge to upgrading operations…that’s where we come in.
   
   We understand the SCADA that might be used to monitor solar or behind-the-meter generation. We can develop a storage plan that maximizes solar use and stays within acceptable load/generation limits. The 20+ years of SCADA experience that Vanja and team bring to the table makes the process much more manageable, particularly for small C&I clients that don’t have someone who can tell them – where do we get this data, where to tie in from a network perspective, what will happen if storage is participating in FR but the generator is hunting for load control. Having an operational and technical understanding of the systems helps navigate this complexity and keeps projects moving."

Thank you, John, for your time and thoughtful responses! We’re excited to have you and looking forward to working more with your team in 2026!

Market Data

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