Seasons of Change

Energy Markets Update

Editors Note: 

The 30 Second Recap

As autumn unfolds, energy markets and policy landscapes are experiencing their own seasons of change. In this edition, we examine key shifts occurring across the regulatory landscape and market dynamics. Key takeaways include:

1. Market Dynamics: Near-term NYMEX natural gas prices reflect a soft winter outlook, while forward power market premiums highlight persistent long-term cost pressures.
2. Regulatory & Electoral Shifts: Post-midterm state and local policies are coming into focus, particularly regarding utility rate approvals and data center siting restrictions.
3. Seasonal Capacity Market Reforms: Grid operators in the Northeast (ISO-NE and NYISO) are transitioning toward seasonal capacity procurement models to address evolving grid reliability needs.

We’ll also look at how E&P companies’ announcements of near-term operational changes may signal that natural gas prices are nearing a market bottom. Finally, we extend our sincere gratitude and best wishes to our group’s Fall 2026 intern, Kaia Moehlis, from Northeastern University, for all of her contributions this autumn.

Table of Contents

• Market Update
• Ballot Box Brownout: Post-Midterm Outlook for Utilities & Data Centers
• Seasons Of Change: Seasonal Capacity Markets Coming to the Northeast
• Cheap Gas: Bottom Of The Well
• Winter Preparedness: OFO - Oh No!

Weekly Natural Gas Inventories

Source: EIA, Veolia

 Energy Market Update 

• Heading into winter this year, energy buyers have a few things to be thankful for. Cheap NYMEX gas, the potential for a “godzilla” El Niño and moderate winter forecasts may all help to counteract broad-based inflationary pressures in power markets.
• The latest EIA short term energy outlook reflects that bearish backdrop. The EIA cut its Q4 NYMEX spot-price forecast by 46 cents to $2.84/MMBtu. Its 2027 forecast was also reduced by 10% from last month, to $2.88/MMBtu.
• Bucking the general downward trend, NYMEX futures did post modest week-over-week gains, led by the 2026/27 winter strip (Nov–March), which is up 7%. Slightly colder weather this week pushed prompt-month NYMEX firmly above $3/MMBtu for the first time in two weeks. The 2027 strip, however, remains less enthusiastic, trading at $3.01/MMBtu–down more than 20% since the beginning of the year.
• Near-term volatility is being driven in part by an anticipated late-week Nor’easter, which is expected to bring cold air and snow to the interior Northeast, with temperatures potentially falling into the 30s as far south as Florida. But the broader winter outlook remains decidedly warm. This winter is expected to be the warmest on record in the US, suppressing natural gas demand for both heating and generation.
• Production trends are beginning to present as a counterweight to weak prices; US producers have been cutting gas output in response. Production now sits at a nine-month low of 109.2 Bcf/d last week. Still, 2026 dry gas output remains on track for a second consecutive annual record, up 4.0 Bcf/d from 2025. Sustained growth is being driven largely by the Permian, where strong crude oil prices and a rising gas-to-oil ratio continue to support output. Permian production is now up more than 60% since 2021.
• LNG exports are another important trend to watch; expansions at Plaquemines LNG, Corpus Christi Stage 3, and Golden Pass lifted average US LNG exports to 17.6 Bcf/d, up 23% year over year. Exports are forecast to rise to 19.0 Bcf/d in 2027, as Rio Grande and Port Arthur are expected to begin production in the middle to latter part of the year.
• Power markets continue to signal a different story. Forward premiums for CAL 2027 remain firmly intact, with PJM forwards implying a 65% premium to the three-year spot settlement. MISO is not far behind, at more than 50%.

Source: ISO Data, Argus, Veolia

• In other words, locking in a fixed power rate in PJM or MISO today for 2027 would mean paying well above historical spot settlements and roughly a 20%–25% premium to the trailing 12-month rate. These are prices that were already viewed as a “worst-case” scenario following Winter Storm Fern and elevated spot prices during 1H-2026.
• On the other hand, various regional differentials have emerged throughout load pockets in PJM where demand from data centers has highlighted meaningful physical constraints. Power in Virginia and Maryland for example can trade at a 20% or more premium to West Hub.

National Headlines You May Have Missed

• Electric and gas utility rate-increase requests reached $4.5 billion nationally in the third quarter, according to PowerLines. The surge reflects the continued pressure utilities are facing from rising costs and infrastructure needs. We’ll take a closer look at the trend in our December coverage.
• Nineteen bipartisan House representatives from states across the country are attending COP31, despite the federal government’s decision not to send a delegation for the second consecutive year. The lawmakers represent a state-level presence at the talks as federal climate policy remains unsettled. Their participation also highlights the growing role of states in international climate discussions.
• New Jersey’s BPU and DEP held a joint hearing on October 15 after RGGI allowance prices topped $7 in two consecutive auctions. Most commenters supported remaining in RGGI, while others argued that higher prices hurt in-state generators and contribute to emissions leakage as Virginia’s recent return to the program reshapes the region’s allowance supply and demand.
• Connecticut and Rhode Island have agreed to nonbinding terms that would set a 20% target for default-service purchases in the spot market. The framework would allow utilities to scale back when conditions warrant while requiring additional risk safeguards above that threshold. Rhode Island Energy separately wants to increase its spot-market share from 15% to 25% in its 2027 Last Resort Service plan, citing summer-price expectations.
• Virginia’s governor is seeking a six-year rate freeze as a condition of approving the proposed Dominion–NextEra merger. The request would lock in customer rates for the duration of the freeze while the companies pursue the transaction. The proposal adds another layer to an already closely watched merger review.

Deal Book

• Amazon signed a 20-year power purchase agreement with Constellation Energy to invest more than $3 billion in upgrades to Maryland’s sole nuclear plant, the 1,790-MW Calvert Cliffs Clean Energy Center. The deal will add about 190 MW of capacity by 2030–32 according to Reuters.
• NRG Energy agreed to sell six natural gas plants totaling 4.9 GW to LS Power for $4 billion in cash. Combined with LS Power’s pending Constellation acquisition, the deal will expand its gas fleet to 11.5 GW across NYISO, ISO-NE and ERCOT. "increasing the company's capacity in key power markets," according to an LS Power press release.

On Our Calendars

Ballot Box Brownout: Post-Midterm Outlook for Utilities & Data Centers

Following the recent midterm elections, readers have frequently asked how energy costs will be affected. While federal impacts are minimal, state and local dynamics—particularly around power rates and data center siting—are poised for heightened scrutiny.

Gas vs. Power: Why Power is More Vulnerable to Local Policy

• Natural Gas Insulated: Interstate pipelines and LNG export approvals fall under federal jurisdiction, keeping natural gas insulated from state elections. NYMEX Henry Hub pricing continues to be driven by national supply, demand, storage, and weather fundamentals rather than local ballots.
• Power Markets Exposed: In contrast, state and local authorities control siting, permitting, tax abatements, and retail rate approvals. While wholesale power markets answer to federal regulators (FERC), state public utility commissions (PUCs) hold direct sway over retail rates.

State & Local Rate Pressure Ahead

• Rising Retail Rates: Power bills have climbed sharply due to local drivers—Pennsylvania is up 58% since 2019 and Ohio 53%—while PJM capacity auctions set three consecutive pricing records this year.
• Ratepayer-First Commissions: Governors appoint utility commissioners in 38 states. Incoming governors across key states (OH, MI, WI, NV, ME) campaigned on appointing ratepayer-first utility commissioners, while Democrats took a majority on Georgia's PSC and gained two seats on Arizona’s commission. Markets expect tougher utility oversight and profit scrutiny than seen in decades.
  
  
• Federal Gridlock Shifts Focus Local: Although Democrats won majorities in Congress, they fell short of the veto-proof supermajority needed to override presidential actions. With divided federal government keeping national energy policy gridlocked, near-term policy shifts will take place almost exclusively at the state level.

Data Centers: The Bellwether of Electoral Opposition

• As the primary catalyst of recent load growth, data centers sit at the intersection of state and local authority over siting, permitting, tax incentives, and grid interconnections.
• Midterm voters opposed data center development in 40 of 41 ballot measures. Results included five full bans (CA, FL, OH), twelve partial bans on larger facilities (KS, ME, OH), and three six-month moratoriums (ME). Harwood, ND was the sole municipality to reject oversight regulations.

Source - Ballotpedia

• Roughly 41% of planned US data center capacity (159 GW) sits in nine states considering or enforcing development pauses, while another 69.2 GW (18% of planned capacity) faces potential tax rule changes.
  

41% of Planned Data Centers Could Face A State Pause Following Midterms

Source - Cleanview

• Texas as the Benchmark: Holding 88.4 GW (23%) of the national pipeline, Texas previously initiated an interconnection queue audit under Gov. Abbott (Batch Zero). Newly elected Gov. Hinojosa has called for a development moratorium until protective legislation is enacted, making Texas the key state to watch to determine whether load growth can proceed without burdening ratepayers.

The major takeaway

The saying goes that elections are local. For the most part, so are the impacts of the recent elections on the broader energy market. Don’t expect any dramatic changes to energy policy, particularly the federal government’s approach to the power generation and renewables. Instead, pay closer attention to changes in how local permitting actions, utility rates cases, and local siting decisions are made for more insight into policy objectives of the new Democratic majority in Congress.

Seasons Of Change: Seasonal Capacity Markets Coming to the Northeast

Capacity markets play a critical role in maintaining electric grid reliability by ensuring sufficient generation and demand-side resources are available during periods of peak demand and system stress. Unlike the energy market, which pays generators for electricity produced in real time, capacity markets act as an insurance policy for the grid, paying for resources simply available when needed during peak demand periods. The design of these markets in the Northeast are slated for major changes over the next two years. Beginning in June 2028, ISO-NE is shifting to a seasonal capacity market with separate summer and winter capacity tags (ICAP tags) rather than a single annual peak. To minimize future capacity costs, your facility must manage peak usage from June-October 2027 to set your Summer 2028 tag, and from May-October each year thereafter for subsequent summer tags. Starting in Winter 2027–28, managing peak usage from November-April each year will set the following year’s winter capacity tag. By contrast, NYISO uses a single annual capacity tag set during July–August peaks, which governs your capacity obligations for both the following summer and winter periods.

In the Northeast, NYISO and ISO-NE manage distinct capacity markets designed to secure grid reliability years in advance. Increasing electrification, data-center demand, renewable integration, generator retirements, and winter reliability concerns are prompting both markets to move beyond traditional annual or predominantly summer-oriented procurement frameworks. We have covered some of the coming ISO-NE capacity market changes in a previous newsletter.

ISO-NE: Moving toward Prompt and Seasonal Procurement

Legacy Process: ISO-NE has traditionally operated a Forward Capacity Market (FCM), procuring capacity ~3 years ahead through annual Forward Capacity Auctions (FCAs). However, this framework limits its flexibility to respond to changing resource availability, retirements, and seasonal reliability risks.

New Process: ISO-NE's Capacity Auction Reforms (CAR) initiative introduces two major phases:

• Phase 1 (CAR-PD – Prompt/Deactivation):

Moves capacity auctions to approximately one month before the commitment period, and reduces the resource deactivation notification period from four years to one.

• Phase 2 (CAR-SA – Seasonal/Accreditation):

For Phase 2, the NEPOOL Markets Committee has approved the tariff changes, with a Participants Committee vote and FERC filing targeted for year-end. Key changes include:

1. Split procurement into summer (May–October) and winter (November–April) auctions.
2. Add a winter gas constraint that pays non-firm gas units less than units with firm fuel.
3. Accredit each resource by its marginal reliability contribution (MRIC), rather than its nameplate qualified capacity (QC). A transition would phase in accreditation over two auctions, with the full implementation by summer 2030.

Source: Veolia, ISO-NE

NYISO: Transition to Address Seasonal Reliability Risks

Legacy Process: NYISO operates an Installed Capacity (ICAP) market where LSEs procure capacity to meet statewide and locational reliability requirements through strip, monthly, and spot auctions. Prices are determined by supply-demand conditions and locational constraints. Historically, NYISO has emphasized summer peak demand. However, increasing winter heating demand and electrification are expected to shift New York toward a winter-peaking system over the longer term. NYISO already introduced separate summer and winter ICAP demand curves in the 2025/26 Capability Year.

New Process: NYISO filed its Winter Reliability Capacity Enhancements in February, accepted by FERC on June 26, effective June 28 (ER26-1431). The changes respond to reliability risk shifting toward winter, improving price signals and strengthening winter resource adequacy:

1. Separate summer and winter NYCA minimum capacity requirements.
2. Separate seasonal locational minimum capacity requirements.
3. Seasonal transmission security limits.
4. Seasonal adjustments to ICAP demand curves.
5. Seasonal allocation of LSE capacity obligations.

NYISO is also revisiting its demand curve design and tariff, targeted for completion by year-end. Proposals changes include a lower maximum clearing price (110–120% vs. 150% today of gross CONE), a kinked curve, and reliability-based zero-crossing points. If adopted, they could reduce price spikes for load in constrained zones.

Source: Veolia, NYISO

Although NYISO and ISO-NE are taking different approaches, both reforms signal a shift toward more granular capacity pricing based on seasonal reliability, resource performance, and deliverability. NYISO's seasonal requirements could increase winter capacity cost exposure, particularly in constrained areas such as New York City, while ISO-NE's prompt and seasonal auctions may reduce forward price visibility and create greater summer-winter price differentiation, especially when winter gas supply is constrained. More accurate accreditation could improve reliability pricing but may raise costs where capacity is scarce.

Energy buyers should closely monitor seasonal auction outcomes, locational capacity requirements, resource accreditation, and demand curve changes. Modeling seasonal peak exposure, especially winter, reviewing fixed versus pass-through capacity provisions in supply contracts, and actively monitoring the developments in these capacity markets will be increasingly important to managing future electricity costs. Veolia helps clients navigate these evolving market structures, assess capacity cost exposure, and develop informed procurement and risk-mitigation strategies to manage costs while maintaining budget certainty.

Cheap Gas: Bottom Of The Well

Why Well Economics Matter to Buyers

When natural gas faces structural downward pressure, the market usually looks for a bottom. The primary benchmarks in the industry include weekly storage reports, weather forecasts, and LNG feedgas data. Underneath those signals sits a more durable force: the point at which producers stop drilling and, in some cases, stop producing. Understanding where that point sits helps buyers judge how much downside remains in the market.

• NYMEX future prices have been on a steady decline since the end of last winter, driven by strong production, healthy storage inventories and mild weather projections. Since the end of March, the 2027 NYMEX strip lost over 25% of its value, its fastest rate of decline occurring over the past month. In response, EQT, one of America’s largest natural gas producers, curtailed 21 Bcfe in Q3 and estimates 10-20 Bcfe of curtailment in Q4. While curtailments don’t necessarily guarantee a price floor, they signal that E&P companies aren’t incentivized to produce into the current market, a fundamental shift in the market.

• The point where producers stop drilling is not an exact science and can vary depending on each E&P company’s location and their evaluation of costs, technology, and debt obligations. Producers will often keep gas flowing from existing wells, especially more mature wells, even when prices are low because they tend to have lower operating costs after they’ve met their return on investment. Natural gas exploration and production has a high upfront cost, which includes land, machinery, and construction. As such, producers are far less likely to drill new wells when prices decline. The varying production price points for new and existing wells helps explain why the market often bottoms through slowdown in activity rather than an abrupt collapse in output.

• We last saw significant curtailment from E&P companies in early 2024 after the warmest winter in recorded U.S. history created elevated storage inventories and depressed pricing. NYMEX settled prices averaged ~$2.50/MMBtu that winter and large Appalachian and Haynesville operators including EQT cut production by over 1 Bcf/d in response. Curtailments continued throughout the summer and NYMEX settlements averaged ~$2.28/MMBtu through the end of 2024 before rebounding in 2025.

• For customers wondering how low the market can go, keep in mind that E&P companies are incentivized to balance supply and demand. As we head into the winter, we’ll keep a close eye on storage levels, pricing, and production activities. If an El Niño brings a warm winter as anticipated, we expect that many of the major players will take action to prevent prices from crashing.

Winter Preparedness: OFO - Oh No!

As winter sets in, gas system restrictions become more commonplace as colder temperatures increase heating demand and infrastructure approaches its operational limitations. Tis the season of the Operational Flow Order (OFO).

An OFO is a directive issued by a natural gas pipeline operator or utility to maintain system reliability by keeping gas receipts and deliveries within specified limits. These orders can be triggered by extreme weather, pipeline maintenance, supply shortages, or imbalances between gas supply and demand.

Why Does This Matter?

For natural gas customers, OFOs can affect both service flexibility and energy costs.

OFOs can require adjustments to usage or coordination with suppliers. For facilities with high natural gas demand, these restrictions can disrupt daily operations. Customers with alternative fuel capabilities may switch fuels to maintain operations, while those without may need to reduce consumption.

OFOs can result in additional market-based or penalty costs when gas imbalances exceed allowable tolerance bands, which may tighten as conditions worsen. For customers using third-party suppliers, noncompliance penalties may be passed through depending on contract terms, meaning even fixed-price contracts can incur additional charges. See the table below for examples from PG&E and SoCalGas.

Know Your Flow : OFO Impact Daily Allowance

OFOs typically impose daily restrictions on natural gas flows, limiting the amount of gas customers can nominate or consume. Knowing your flow is important, as customers should understand their typical daily consumption and maximum daily allowance to ensure they stay within permitted limits. The most common OFO directive is to limit consumption to the contractual daily limit, which is usually the monthly nomination divided by the days in the month.

OFOs are different from curtailments, which require customers to partially or completely reduce natural gas usage. However, the two can occur together during periods of system stress, potentially requiring customers to adjust or suspend operations.

OFO Dynamics

Consider January 2026. As temperatures began trending downward in Virginia, Columbia Gas of Virginia issued an OFO on January 15, followed by several extensions.

Source: Veolia, Weather Underground

Virginia was not alone. During January's cold snap, utilities across Ohio, Illinois, Missouri, and Oklahoma also issued OFOs in response to changing system conditions. Below is just a small sample of utilities we’re monitoring.

Source: Veolia

Formal OFOs establish specific operating requirements and potential penalties, advisories and warnings alert customers to potential or developing constraints, and conservation notices encourage reduced consumption.

Preparing for an OFO

Unexpected costs and operational disruptions can be reduced by monitoring weather forecasts and pipeline notices, communicating with suppliers, and understanding contractual requirements. As winter demand rises, staying informed and maintaining flexibility can help customers navigate natural gas system constraints.

• Stay Informed: Confirm your primary point of contact with your natural gas supplier or pipeline operator. OFO notices are typically communicated by email, and customers should contact their supplier or energy advisor with any questions.
• Know Your Flow: Understand your typical daily natural gas consumption, contracted daily allowance, and maximum permitted flow to ensure compliance with potential restrictions. Sometimes operations must continue, but you should be cognizant of the potential cost impacts.
• Plan for Curtailments: Prepare for potential partial or complete reductions in natural gas usage by identifying operational adjustments or alternative fuel options to minimize disruptions. These events are rare in most parts of the country, but they do occur and they often coincide with extreme weather and during cold snaps.

Market Data

Market data disclaimer: Data provided in the "Market Data" section is for the newsletter recipient only, and should not be shared with outside parties.