Editor’s Note: In this update, we track early-season gas volatility as inventories peak near 4 Tcf and LNG feedgas demand repeatedly tops 20 Bcf/d, lifting 2026–2027 strips back above $4.00/MMBtu. Policy signals remain mixed: DOE is weighing emergency actions to extend coal plant operations for winter reliability, COP30 proceeds without official U.S. federal participation, and Pennsylvania has formally withdrawn from RGGI. State-level shifts—including Massachusetts’ proposed RPS rollback—underscore growing affordability pressures. Meanwhile, evolving EV adoption trends and accelerating data center growth are reshaping long-term load forecasts, pushing grid operators and policymakers to lean more heavily on demand response and flexible-load strategies.
Source: EIA
Our analysts have been tracking the shift in Exploration & Production (E&Ps) companies’ activity from wet gas to dry gas plays all year. Despite a declining total rig count, the US has been producing more natural gas than ever before. The growth pencils out in strategic pivots with drillers migrating away from oil-rich fields and flocking to dedicated natural gas hotspots. Whether these efficiency improvements and production gains can keep pace with accelerating demand will ultimately determine if natural gas prices and shareholder returns stabilize in 2026 - or if unforeseen supply constraints push prices significantly higher for buyers in the second half of 2026.
This week, let's jump right into a visual: the map below shows the lower 48 states and where our largest oil and natural gas reserves are being extracted for domestic consumption and international use.
Source: EIA, Baker Hughes Rig Counts
Source: Baker Hughes Rig Counts
Despite a record quarter ahead of expiring tax incentives, electric vehicles are losing momentum in the United States. Sales growth has tempered, pushing major automakers to dial back expectations. For electric grids, and looking specifically at New York’s this week, we consider how changes in the EV market could impact power forecasts and infrastructure planning.
What’s Actually Happening in the EV Market
After years of double-digit growth, U.S. EV adoption is now increasing more slowly than earlier projections made during the first half of the decade. The EIA charts that 2024 and 2025 pure play EV sales - referring to lightweight vehicles that run only on plug-in power without a hybrid gas motor - have softened. Industry experts point to high vehicle prices, charging accessibility concerns, and the phase-out of federal tax credits for many models.
EIA Quarterly U.S. Light-Duty Vehicle Sales by Powertrain 1Q15-1Q25
Source: EIA
Automakers are responding. Ford and other domestic majors such as General Motors, have pushed back on production targets and capital commitments for several EV programs. Internationally, Mercedes-Benz and Volkswagen have extended timelines for the phaseout of combustion engines.
NYISO’s View: EV Demand Still Grows
If EV adoption significantly underperforms state projections, NYISO risks stranded generation and transmission assets. Even if data centers were to step into some of this demand, NYISO may need to redirect billions in planned infrastructure investments away from distributed charging networks and residential grid upgrades toward concentrated, high-capacity transmission serving data center hubs.
This rebalancing could also impact the state's renewable energy buildout strategy, as data centers require reliable baseload power rather than the flexible, time-shifted charging loads that EVs were expected to provide for grid balancing. The state's 2050 decarbonization goals may need recalibration if transportation electrification - a key pillar of emissions reduction - fails to materialize at projected rates we’re currently seeing in their reports.
In response to ongoing concerns about rising energy costs, a group of Massachusetts lawmakers unveiled a sweeping energy-affordability bill (H.4744) that could reshape the state’s clean energy trajectory by scaling back statewide emissions-reduction targets, among other changes.
H.4744 received unanimous 7-0 approval from the House Committee on Telecommunications, Utilities, and Energy, and now sits before the House Ways and Means Committee for review. While the bill remains in early stages, the focus on affordability from both legislative branches and Governor Maura Healey suggests momentum may be building for its passage.
The legislation builds on Governor Healey’s Energy Affordability, Independence & Innovation Act, filed earlier this year, which aimed to expand the state’s clean energy procurement authority, accelerate utility interconnection processes, and explore alternative energy sources such as nuclear and geothermal.
Sponsored by Rep. Mark Cusack, H.4744 would effectively render the state’s 2030 emissions target non-binding by altering the Renewable Portfolio Standard (RPS) trajectory. The bill would:
These changes would effectively delay the already-scheduled 3% annual RPS ramp-up planned for 2026-2029, softening near-term clean energy requirements in the name of rate relief.
The RPS currently costs Massachusetts ratepayers over $1.2 billion annually, but it also supports a significant in-state renewable energy industry and is deeply intertwined with other policies and programs, including Boston’s Building Emissions Reduction and Disclosure Ordinance (BERDO). Additional provisions in the bill would:
Mass Save programs currently represent roughly 7% of the electric rates charged by Massachusetts utilities. The proposed cuts would yield less than 1% in rate savings, according to program estimates, compared to the $2.8 billion in benefits Mass Save delivered in 2024. By statute, Mass Save’s portfolio must maintain a benefit-cost ratio greater than 1.0, meaning the programs must return more in energy and non-energy benefits than they cost.
We’ve been tracking a broader regional trend as Northeast states reassess the pace and structure of their clean energy commitments, including recent moves in New York and Pennsylvania. Against this backdrop, a central question looms: can Massachusetts still credibly achieve net-zero emissions by 2050 if it weakens near-term requirements and funding mechanisms?
In an era of higher construction and financing costs, rising import duties, curtailed incentives, and unpredictable federal permitting timelines, the challenge is not unique to the Bay State. The emerging question for policymakers across the region - and nationally - is whether any state can hit its long-term net-zero targets while simultaneously dialing back the very policies designed to get it there.
Last week, the EIA published its Short-Term Energy Outlook, which predicted that electricity sales will increase by 2.4% in 2025 and an additional 2.6% in 2026. With rising demand and associated costs (see charts below), ratepayers, utilities, and regulators are growing anxious about the source of new supply. Demand response is a part of the solution. In a previous newsletter, we briefly touched on how demand response can provide the quickest path to relieving scarcity and improving grid reliability. In this article, we will take a deeper dive into where we see demand response programs heading in 2026.
Source: EIA
The EIA’s outlook noted that growth will be most significant in areas with increased data center activity, such as Northern Virginia, Texas, Ohio, etc. Stakeholders are increasingly proposing that data centers be equipped with flexible demand capabilities as a prerequisite for interconnecting to the grid. Large load integration can be expensive for ratepayers due to: (1) the impact of regional constraints on price and reliability, (2) significantly higher clearing prices for energy and capacity due marginal economics of price formation, (3) cost shifting as large loads are able to contractually secure supply while burdening the bulk power system with higher costs, and (4) infrastructure upgrades. Reducing load during peak demand hours reduces the immediate need for these expensive upgrades and real-time marginal price increases.
Many states are trying to bring their laws up to date with the harsh realities large loads present, as well as the opportunities they offer. Most notably, SB 6 in Texas requires large electricity consumers (75 MW or greater) to participate in mandatory demand management programs and possess remote disconnection capability, even allowing the grid operator to cut power during grid emergencies. Other states, including Virginia, Maryland, New Jersey, Georgia, and California, are considering similar measures.
Whether mandated by law, economics, or necessity, stakeholders are increasingly turning to demand response across all customers as an effective way to promote grid reliability and protect ratepayers. While utilities and grid operators are principally concerned with reliability, many of our customers see the benefits of demand response as an effective way to reduce their electric costs by lowering their facility’s demand charges. These come in many flavors, including monthly ratchet, monthly coincident peak, and seasonal coincident peak. Reducing load during a few peak hours can result in hundreds of dollars in savings per kW, depending on location.
Load reduction can be a manual process, requiring facility managers to be aware of when peak-demand days occur and respond accordingly to reduce load during those periods However, the future of demand response can be much more automated through integrated energy management systems. By integrating with BMS in real time and leveraging predictive analytics, these systems can evaluate opportunities to reduce load and optimize operations without manual intervention. This could evolve into automated dispatch sequencing involving pre-cooling or pre-heating, and cycling between different mechanical equipment.
Recognizing the increased importance of demand response in addressing reliability, efficiency, and cost concerns, Veolia acquired IceTec Energy Services this past summer and is integrating the company under the Veolia Flexible Energy Services service line. Flexible Energy Services is a digital and distributed energy management technology, leveraging its integrated systems to automate demand response efforts. According to the team, the market for more sophisticated energy management is currently worth $20.8B and is set to more than double to $41.2B within the next five years. Customers that have partnered with IceTec have achieved impactful results, including:
As demand response has proven a successful solution to bolstering grid reliability and mitigating the impact of rising utility rates in recent years, it’s easy to see why the market has nowhere to go but up. Be on the lookout for the next edition, where we’ll interview DR expert Matthew Wolfe from Veolia Flexible Energy Services. If you would like an introduction to the Flexible Energy Services technology platform or to learn more about its capabilities, please reach out to commodity@veolia.com!
Market data disclaimer: Data provided in the "Market Data" section is for the newsletter recipient only, and should not be shared with outside parties.