Power Struggles

Energy Markets Update

Editors Note: 

The team is back from our summer break to inform you of moves in commodity markets and important news shaping our industry. This newsletter is slightly longer than our average run, but there is a lot to catch up on!

We cover the lasting impacts of the Iran conflict, the rapidly evolving regulatory landscape for data centers and large loads, changes to federal GHG standards, challenges facing NECEC, and DASI reforms

Table of Contents

• Energy Market Update
• Iran Conflict & Commodity Fundamentals
• Large Loads: The Fragmentation of Datacenter Regulation
• Trump Administration Guts GHG Standards
• Water Under the Dam? Not Quite for NECEC
• Cut Flowers: Day-Ahead Ancillary Services Initiative (DASI) Gets Trimmed

Weekly Natural Gas Inventories

Source: EIA, Veolia

Energy Market Update

• The October NYMEX contract rallied 18% into its final week of trading before closing out $3.00/MMBtu this week, close to its average value over the past month. Last week’s gains were driven by temporary factors, including a West Virginia pipeline disruption, tighter storage builds, and strong LNG feedgas demand. Futures retreated this week as the pipeline returned to service and shoulder-season demand remained subdued.
• The 2027 NYMEX strip has continued its decline since the summer, currently trading at $3.21/MMBtu. The 2028 and 2029 strips have remained relatively stable over the past few months, trading at $3.73/MMBtu and $3.71/MMBtu respectively.
• NYMEX settled ~6% lower this summer from June through August compared to 2025, largely driven by record setting U.S. natural gas production in 2026 and healthy storage inventories entering the 2026 injection season, which were reinforced by sustained injections.

Source: EIA

• 2026 is on track to be a record year for dry natural gas production, exceeding the previous year’s production levels of 106 Bcf by 4% in the first half of 2026, and averaging ~112 Bcf/d in September. Storage injections, while strong through 2026, have not followed the same record setting trajectory due to increased demand from LNG and power generation due to hot summer.

Source: EIA

• The EIA reported a 64 Bcf injection this week, 2.4% above the 5-year average but 3.9% below the injection recorded during the same week last year. Several weeks of historically low storage injections tightened the storage surplus compared to the 5-year average and supported the market.
• US LNG exports averaged 17.4 Bcf/d in 1H26, up 23% year-over-year, according to the EIA. Expansions from Plaquemines LNG, Corpus Christi Stage 3, and Golden Pass increased exports at the fastest rate since 2016. Gas flows to the nine major US LNG export plants increased to 18 Bcf/d in September from 17.3 Bcf/d in August, but below the 18.96Bcf/d record set in April. Forecasts still indicate LNG could reach 27 bcf/d by the end of next year.
• Trends for 2027 power futures diverged across ISOs in September trading. NYISO and ISO-NE prices remained relatively stable, declining only 1-2% with minimal volatility. MISO and PJM demonstrated the strongest upward momentum, going up 11-13% over the month, while ERCOT prices rose modestly. Similar pricing trends were observed across the 2028 and 2029 forward curves within each ISO, indicating that market participants are pricing similar regional dynamics across the multi-year forward curve.

Source: Veolia

• According to NOAA, there is 100% certainty that an El Niño will persist at least through March 2027, with a high likelihood it will be a very strong El Niño. In the Northeast, this signifies a mild winter and a bearish outlook for natural gas markets - we’re already taking bets that Punxsutawney Phil will not see his shadow in February. Previous El Niño’s have also reduced wind output in the central US and solar output in the western US, according to an analysis by Wood Mackenzie.
• NOAA’s short-term outlook shows a cooler pattern emerging through much of the Northeast and above average temperatures in the western half of the country.

Source: NOAA 

• PJM is launching a one-time Reliability Backstop Procurement (RBP) to address a 6,831 MW capacity shortfall in its 2028/2029 auction, with bidding from September 30–October 21 and results expected in December. The procurement could secure roughly 6 GW of new capacity through contracts of up to 15 years and are open to gas, nuclear, storage, and clean resources , with a maximum willingness to pay equal or a MW-weighted average of $555/MW-day. The effort reflects growing demand from large loads and data centers, while location and cost allocation remain key issues as new generation may require transmission to serve concentrated load centers such as Northern Virginia.
• In addition to the RBP, PJM filed an August 13 proposal implementing three elements of its large-load framework: a Large Load Registry, Interim Resource Adequacy Service (IRAS), and compensation for curtailed large loads. IRAS would allow new 50 MW+ loads to connect without fully secured capacity, with uncovered demand curtailed first during reliability events; Bring Your Own New Capacity (BYONC) allows customers to reduce this exposure by bringing qualifying new capacity that must participate in PJM’s capacity auctions for 10 years. Curtailments under IRAS would be compensated at up to 50% of PJM’s Non-Performance Charge Rate, while from 2029/30, uncovered incremental large-load demand would be excluded from the capacity auction demand curve until supported by BYONC or RBP capacity.
• The House passed the Ratepayer Protection Act (H.R. 9340) 417–3 on Sep 16 to limit data center cost shifts. The bill requires states to consider standards so that loads over 100 MW pay the full incremental cost of the generation, transmission, and distribution infrastructure, rather than shifting those costs to existing customers. However, Senate Democrats blocked the bill on September 30, arguing it does not go far enough to protect against rising electricity costs, which will push any further consideration of the issue until after the midterm elections.
  
  Regional Stories

• With energy affordability a growing concern in Massachusetts, Senate leaders proposed legislation in June 2026 that they estimate could save ratepayers more than $14 billion over 10 years. The proposal would phase out the Gas System Enhancement Program, which funds gas pipeline replacements, while addressing utility costs and preserving energy efficiency funding.
• FERC approved major changes to the Day-Ahead Ancillary Services Initiative (DASI) program in NEISO last month. We cover its impacts on the New England market in more depth below.
• Despite federal support, the proposed 125-mile Constitution Pipeline faces an uncertain future as it struggles to secure commitments from utilities and natural gas producers. The pipeline would transport Pennsylvania gas toward New York but would not directly serve major Northeast demand centers. Analysts warn that existing connecting pipelines are already nearly full during winter, limiting the project's ability to alleviate regional supply constraints without additional infrastructure.
• FERC has reaffirmed the 9.57% base ROE for ISO-NE transmission owners and upheld approximately $1.5 billion in retroactive refunds to customers for historical overcollections dating back to 2011, including interest. The refund deadline remains May 20, 2027, although the transmission owners are continuing their legal challenges, including a request for a stay from the D.C. Circuit. For customers, the decision could provide significant near-term rate relief through the refunds and lower ongoing transmission costs from the reduced ROE, although the final timing and amount of refunds remain subject to the appeals process. New England RNS rates remain high, however, reinforcing the value of managing or avoiding this cost where possible.
  

 Iran Conflict: Commodity Fundamentals 

Oil and refined fuels

• Seven months into the U.S.-Iran War, the market seems less prone to panic but is still trying to determine just how much pain the global oil supply chain can endure, and for how long. Brent crude is currently trading around $105 per barrel – elevated, but still well below the wartime peak of $126/barrel seen in April.
• Look beneath the surface and there is more disruption than meets the eye, however. While the financial market, represented by the Brent crude index, trades around $105, many buyers report physical prices that are as much as $25 higher. This represents an inefficiency in the physical market, and/or an undervaluation of the physical market, probably both.
• The real constraint in today’s oil market is not necessarily a shortage of aggregate crude–the unrefined fossil fuel–but insufficient refining capacity to convert crude into usable products consumers rely on such as diesel, jet fuel, and gasoline. The economics of this conversion are reflected in the “crack spread,” or the premium that refined transportation fuels command over crude oil. That spread has reached a multiyear high amid the war and the ongoing conflict in Ukraine, highlighting the downstream effects of refinery shortfalls even as crude prices have recovered throughout the year.
  

Source: TradingTools

• Global refining capacity was facing a structural shortfall before the war. Dozens of European refineries closed during the pandemic, while many others have continued to age and approach permanent retirement. The United States also lost more than 1.2 million barrels per day of refining capacity as a result of permanent closures before the conflict. Since February, war-linked attacks on refineries and damage to infrastructure in the Middle East, Russia, and China have reduced global refining capacity by an additional 9%.
• This helps explain why global shortages of jet fuel and diesel have persisted for months, even after oil began to flow again.

Natural Gas 

• Globally, disruptions to LNG shipments from Qatar and other Middle Eastern producers have constrained global supply. New export capacity elsewhere is expected to offset much of the decline, though continued disruptions could sustain international natural gas price volatility.
• U.S. Henry Hub front-month futures prices declined 9% between the weeks ending February 27 and April 24, 2026, as shown in the graph 2027 Forward - NYMEX vs. Power chart above, as ample supply and softer consumption offset growing export demand. However, continued LNG expansion could create additional upside price pressure if domestic fundamentals tighten.
• El Niño is strengthening, with NOAA forecasting more than a 100% chance of a “very strong” event during fall and winter 2026–27, defined as a temperature index greater than or equal to 2°C above normal. If realized, moderate temperature patterns could styme gas demand and keep a lid on both gas and power prices.

Source: Claude

• For businesses, these conditions create greater uncertainty around future energy costs. The price of heating oil and refined products is under the most stress in the short term, but with geopolitical risk, growing LNG exports, demand growth, and winter weather all now influencing the market, staying flexible and monitoring price movements is crucial to managing energy budgets and finding value in the market.

Large Loads: The Fragmentation of Datacenter Regulation

The rapid growth of AI is driving a surge in U.S. data-center development and electricity demand. The large and highly concentrated loads are placing new demands on the power grid and raising questions around interconnection, reliability, infrastructure investment, and cost allocation. With no uniform national framework for addressing these loads, federal regulators, RTOs/ISOs, states, utilities, and local governments are taking different approaches to managing this growth.

What are Large Loads?

• In the power planning world, “large load” typically refers to electric demand significantly large enough to materially affect the electric grid, requiring special interconnection, planning, reliability, and cost-allocation considerations. The term has entered the common vernacular with the increasing prevalence of datacenters, however there is no single national definition or regulatory framework for large loads. Thresholds vary by RTO/ISO, utility, and state, with 25 MW being increasingly used as a practical regulatory threshold, though some frameworks use 50 MW, 75 MW, or 100 MW+.

Source: Interconnection.fyi

• The gaps are wide: SPP’s and Georgia’s definitions, for example, differ by a factor of ten. FirstEnergy in Ohio has asked to apply its data center tariff to any data center of any size at all. A 40 MW facility could simultaneously be a regulated data center under AEP Ohio’s tariff, an ordinary commercial customer in Georgia, Texas and Oklahoma, and, if interconnected at 69 kV or below in SPP - High Impact Large Load.

How large loads are regulated?

• Like the ambiguity surrounding the definition of large loads, there is no single regulatory framework governing their development. Instead, regulation occurs through overlapping layers of federal, RTO/ISO, state, utility, and local authority, with each addressing different aspects of a project from wholesale market access and grid reliability to retail rates, infrastructure costs, permitting, and community impacts.

Source: Veolia

• This layered structure means a single large load can be subject to multiple definitions, requirements, timelines, and approval processes, creating a regulatory landscape that varies significantly by market and state.

• Without a unifying framework, jurisdictions are adopting different approaches and solutions to grapple with the growth of large loads. Federal policy prioritizes faster data-center development through streamlined permitting and environmental reviews, but it does not override state and local authority over zoning, utilities, and environmental approvals. Meanwhile, many RTOs/ISOs, states, utilities and local governments are pursuing large-load legislation focused on system reliability, cost responsibility, energy and water-use reporting, financial commitments, ratepayer protection, and community & environmental impacts. Some states are even considering construction moratoriums. The table shows how these approaches are evolving across key jurisdictions.

Source: FERC, RTOs, Utilitydive, Interconnection.fyi, PUCs, Others

• States are converging on one goal to make large loads more accountable for the grid costs and risks they create: Texas is tightening queue and financial requirements, Georgia is using large-load contracts and ratepayer protections, Oklahoma is enabling self-generation, and Utah allows large loads to bypass utility generation service while retaining transmission access.

• PJM is similarly accommodating large load growth, but with conditions. It is developing a mechanism that increasingly requires new loads to bring their own power supplies, curtail during system stress, and avoid imposing incremental reliability costs on existing customers. Its one-time backstop procurement to address the 2028-2029 capacity auction shortfall is also closely linked to rapid large load growth and would add capacity while working on longer-term reforms. However, whenever it clears, PJM assigns the cost to each utility zone, leaving states to decide how it gets distributed among retail customers. For ratepayers, and for large loads themselves, the same procurement could therefore mean very different bill impacts depending on the state in PJM.

Therefore, the overall trend is clear: Federal → enable growth; RTOs → manage reliability/interconnection; States → control costs, siting, and community/environmental impacts. This division is creating a growing gap between federal efforts and those of RTOs, state, and localities.

• Public sentiment is widening that gap. A poll from Aug ‘26 shows a sharp shift in public opinion against data centers, with 71% of Americans now opposing a new facility near their home, up from 42% in September 2025.

Source: Heatmap

• Public opposition is also translating into local policy activity and is speculated to play a substantial role in the midterm elections. This November, residents in 28 localities across six states will vote on data center ballot measures, with proposals ranging from construction bans to permanent moratoriums on new facilities. This growing local activity adds another layer of uncertainty for developers and highlights the increasingly complex environment in which large-load projects are being planned and permitted.

Source: Multistate.US

• Large load thresholds vary widely, so the same facility can be regulated in one jurisdiction and treated as likely any other industrial customer in another. At the same time, costs are shifting toward large loads, which are increasingly expected to fully fund their energy demand and any grid buildout or expansion and to include ratepayer protection provisions. This is a dramatic shift from the conversation two years ago when co-location and bypass of the transmission system altogether seemed to have momentum. Finally, bring-your-own-power is spreading, with self-supply, new-generation requirements, and curtailment provisions increasingly serving as the price of faster interconnection.

• The large-load landscape is still evolving, and regulatory requirements will likely remain dynamic across federal, RTO/ISO, state, utility, and local jurisdictions. Our team will continue to track these policy and market developments, assess their implications for energy costs, reliability and procurement strategies, and help clients navigate the increasingly complex and fragmented regulatory framework surrounding large loads and data centers.

Trump Administration Guts GHG Standards

The Trump Administration eliminated GHG standards for power plants and weakened standards for automobiles in September. The electric power and transportation sectors are responsible for over half of the country’s total GHG emissions, with ~28% from transportation and ~25% from power generation.

 Source: Claude & EIA GHG Inventory

• On September 14th, the Environmental Protection Agency (EPA) announced the repeal of carbon emissions limits for coal and gas-fired power plants that were previously approved during the Biden Administration. The EPA also proposed removing every remaining greenhouse gas emission standard for the power sector, which is currently being held for public hearing.

• In 2024, the EPA implemented strict GHG emissions limits for new and existing fossil fuel fired power plants under Section 111 of the Clean Air Act. The regulations applied to existing coal-fired plants and new gas plants that operate more than 40% of the time and plan to continue operating through 2039. Such facilities were required to eliminate 90% of their carbon dioxide emissions via carbon capture and storage (CCS) technologies or co-fire with natural gas by 2032.

• The current administration argues the Biden-era regulations exceeded EPA’s authority under Section 111 of the Clean Air Act and created inefficient use of natural gas, driving up electricity prices. The EPA argues that repealing CO₂ standards for power plants will save $310 billion by reducing compliance costs, which will trickle down to ratepayers. EPA also argues that GHG emissions from power plants have “no material impact on global climate change” and any analysis of associated public health harms are too convoluted to fall under the scope of power sector regulation. (The Biden administration had estimated that by 2035 its regulations would prevent 1,200 premature deaths, 360,000 cases of asthma attacks, avoid 48,000 school absences and 57,000 lost workdays.)

• This week the Trump administration also announced changes to the Corporate Average Fuel Economy (CAFE) standards, which sets average fuel economy regulations for car manufacturers. The new rules require most vehicles to average 34.9 miles per gallon by 2031, a ~30% drop from the previous standards of 50.4 miles per gallon. Affordability was again the central rationale behind the decision. However, analysis from the USDOT shows that average cost per vehicle will decline by $1,289 but increase fuel costs by over $1,600 over the vehicle’s lifespan.

Water Under the Dam? Not Quite for NECEC

The New England Clean Energy Connect (NECEC) was envisioned as a cornerstone of Massachusetts' clean energy strategy. Under 20 year contracts, Massachusetts utilities agreed to purchase approximately 9.55 TWh of Hydro-Québec hydropower annually, equivalent to roughly 20% of Massachusetts electricity demand. The project was intended to provide low cost, low carbon electricity, displace fossil fueled generation, reduce wholesale power costs, and reduce the need for additional renewable generation and associated credits.

Map of the New England Clean Energy Connector

Source: Iberdola - New England Clean Energy Connector

Those benefits have been tested almost immediately. After a series of interruptions during its first year of operation, Massachusetts utilities and Hydro-Québec (HQ) have filed dueling lawsuits over their contractual obligations.

What Happened?

• Lower than expected flows: NECEC has averaged below its approximately 1,200 MW design capacity throughout its first year.
• Winter outage: The most consequential interruption occurred during the end of January cold snap, when New England demand and wholesale prices were elevated.

Source: ISONE External Interface Metered Data

• Replacement power: Eversource, National Grid, and Unitil say they incurred approximately $40 million in replacement-power costs during the 12-day winter outage.
• Clean-energy impact: The utilities also had to replace the clean-energy attributes associated with power that was not delivered.
• Two lawsuits: Massachusetts utilities argue that HQ breached its contractual obligations, while HQ argues that the curtailment was necessary to protect Québec's grid during an emergency and falls under the contracts' force-majeure provisions.
• Counterclaim: HQ is also seeking ~$50 million for power it says it delivered in January and February but was not paid for.

While low flows have put the NECEC on pace to underprovide its annual contracted volumes, the value of its’ imported power changes dramatically depending on the New England power market’s current conditions.

Our analysis of NECEC’s 2026 underperformance periods highlights the difference:

• January 24–31 cold snap: NECEC under-performance was associated with approximately $86/MWh higher median wholesale energy prices, especially during extreme weather conditions.
• April–Aug: NECEC’s impact on power prices while performing vs underperforming was much smaller, ranging from -$12/MWh to +$7/MWh in median prices.
• Takeaway: NECEC's ability to drive down power prices is concentrated during crunch times when power supply is scarce and expensive, like the January cold snap. The pending litigation should focus on incentivizing HQ to export energy to New England on the NECEC during these grid stress periods (possibly through capacity accreditation), mitigating the need for costly discussions on who pays for replacement power in the future.
  

Source - ISONE External Interface Metered Data

What to Watch in the Current Litigation

• Who pays for replacement power? The lawsuits will determine how the contracts allocate costs when NECEC cannot deliver its contracted supply.
• How is force majeure interpreted? The case could establish how emergency curtailments by Québec's grid operator affect Hydro-Québec's delivery obligations.
• Are make-up power or other remedies required? The outcome could clarify how future shortfalls are compensated.
• What happens to the clean-energy attributes? Missing hydroelectric generation can also create additional REC or clean-energy procurement requirements.

The lawsuits focus on who pays for NECEC's failures, but the real issue is more fundamental: the project's value is heavily dependent on its timely supply during grid stress events. NECEC drives power prices down the most when New England faces constrained power supply volumes coinciding with spikes in electricity prices, exactly when customers need it most. When NECEC fails during these critical periods, utilities must scramble to buy expensive replacement power, which severely takes away the savings the project was supposed to deliver. In other words, NECEC works best when it's needed most, but that's also when its failures hurt the most.

Cut Flowers: Day-Ahead Ancillary Services Initiative (DASI) Gets Trimmed

• Where some see flowers, most see weeds. On September 14, FERC accepted ISO-NE’s proposed changes to the Day-Ahead Ancillary Services Initiative (DASI), a move that is expected to significantly reduce the cost of the program to buyers in New England.
• The FERC docket for the case is (ER26-3176-000) and ISO is expected to implement all reforms by October 22.
• DASI officially went into effect on March 1, 2025. In January, the Internal Market Monitor recommended improvements to the program that had at that point contributed to $290 million in “unnecessary” costs in the program’s first year. With the real carnage occurring December through March, our estimates put that figure closer to $1B over budget. NEISO had originally forecasted an average cost to load of $1.50 per MWh for the initiative. We are tracking year 1 costs over $9 per MWh.
  

Source: NEISO data, Veolia analysis

• Some of the key reforms to the program in this filing, and an earlier administrative change include:
  • Reduction in the actual reserve purchase quantity: NEISO reduced the Forecasted Energy Requirement (FER) demand quantity to account for front-of-the-meter solar and wind energy.
  • Improved the accuracy of the Day-Ahead price forecast used to derive the program close out cost. Simply by using a more accurate forecast, this narrows the arbitrage opportunities and revenues for participating generators. In August, NEISO made an administrative update to their day-ahead forecast, which now relies on third party market values from Intercontinental Exchange (ICE) when markets are more volatile and risk of DASI close out costs rise exponentially.
  • Adjusts the evaluation metrics for the market's safety mechanisms. Allows the Internal Market Monitor (IMM) to flag and counter potential exercises of localized market power more efficiently.
  • Establishes a Strike Price Floor: the floor reduces risk for participants, and should improve efficiency by fostering more competition.
• While administrative changes have already appeared to make an impact, the real test will be this upcoming winter when higher prices and day-head vs real-time price deviations have yielded higher program costs.

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.