Crude Tactics

Written by Weekly Market Update | Jan 16, 2026 2:50:53 PM

Energy Markets Update

Editor’s Note: Happy New Year! In this edition, we examine recent developments in Venezuela and the relationship between global oil markets & domestic natural gas. We also explore recent setbacks facing New England's offshore wind industry, PJM's planned implementation of flexible data centers to address rising power costs, ISO-NE's evolving capacity market design & the latest developments to the DASI program.

We are also excited to welcome Olivia Parsons, who joins our team this month as an intern from Northeastern. Wishing you an insightful read as we kick off 2026!

Weekly Natural Gas Inventories

Source: EIA, Veolia

Energy Market Update

Energy markets kicked off the New Year on a sharp downtrend. Robust gas production and moderating weather took a bite out of the frothy risk premiums for the balance of winter 2025/2026.
NOAA forecasts persistent warmth across the South while northern regions face late-January cold. With just a few weeks of relative uncertainty remaining in the core of winter, it will take a significant shift in the forecast to shake the bearish sentiment.

Source: NOAA

Strong January gas production, averaging 110 Bcf/d (6% above year-ago levels), continues to sustain bearish pressure.
The EIA’s most recent storage report noted a 71 Bcf draw, falling 20% below forecast. Even so, the season-to-date gas withdrawal of 775 Bcf remains the strongest in three years.
A fundamental supply-demand imbalance has emerged: production is up by ~7 Bcf/d YoY, while demand from residential & C&I customers is down 11 Bcf/d compared to this time last year. Increased LNG demand from Golden Pass is expected to rebalance the market but the timing is slightly off.
The 2026 NYMEX strip fell 10% over the past month while ‘27/‘28 strips posted moderate declines of 3.6% and 2.5%, respectively.
Power futures have followed gas lower: PJM’s 12-month strip down 15%, ISO-NE’s ‘26 down 5%. ERCOT maintains the largest forward premium at 29% due to lower prices last year and anticipated congestion from new large data centers initiating service this year.

Source: S&P, Veolia

In other news, this week:

Indeed, the US military captured the President of Venezuela last week and will now ostensibly be “running” the country, or maybe just its oil industry. If you had that on your bingo card or Polymarket call option, congratulations. We will cover the story and broader impacts on US markets in more detail below.
Reuters is reporting a possible agreement between a coalition of governors in the Mid-Atlantic states and PJM to extend price caps on future PJM capacity auctions. Stay tuned.
More than 70 New York officials are urging the PSC to reject Con Edison’s three-year proposal to raise utility rates, arguing it would deepen the affordability crisis and push more residents into debt. Despite being lower than a previous proposal, which we covered last quarter, the plan would increase average bills annually from 2026-2028, with proposed yearly rate hikes of roughly ~3% for electric and ~5% for gas.

From Crude to Clued: Oil Market Basics

With WTI hovering around $60/bbl and recent headlines about US involvement in Venezuelan oil operations, a key question emerges: How do shifts in the global oil market affect what Americans pay for domestic energy , namely natural gas? The answer lies in understanding the interplay between domestic production of both oil and gas and international price benchmarks.

Quality & Correlations

Not all crude oil is created equal. Crude is classified as light/heavy (density) and sweet/sour (sulfur content). Light sweet crude is most valuable because it requires less refining to produce gasoline and diesel, while heavy sour crude needs more processing.
The US oil market revolves around WTI (West Texas Intermediate), a light, sweet crude from the Permian Basin that's ideal for producing gasoline, diesel, and jet fuel. The international benchmark, Brent crude from the North Sea, underpins pricing for roughly 60% of globally traded oil.
WTI and Brent are highly correlated due to oil's global nature. Their price spread reflects transportation costs, regional supply-demand balances, and quality differences.
In contrast, WTI and the US natural gas index (NYMEX) show weak correlation due to distinct supply and demand dynamics. The US gas market is largely physically isolated from global gas markets, so price changes do not shift supply, for now. LNG exports could alter this picture somewhat, but we are a long way off.
So while oil and gas increasingly come from shale formations in the US, sometimes even in the same regions, their market fundamentals differ enough to prevent strong price correlations. On rare occurrences, oil and gas can demonstrate apparent correlation (see highlighted period in the box below, which occurred shortly after Russia’s invasion of Ukraine, wherein surging oil rates actually impacted the cost of production for gas), but these brief periods of apparent correlation are mostly the result of exogenous economic or geopolitical shocks.

Source: Federal Reserve Bank of St. Louis
So there are some links between the two US markets, particularly with respect to drilling activity, incentives, and production costs, but they tend to present at price extremes. Our previous coverage Where have all the Drillers Gone provides more details on the subtle interplay between the two commodities.

Summary of Market Drivers

NYMEX is largely driven by domestic shale production and natural gas storage inventories, though LNG exports could globalize this market over time. Natural gas demand is highly seasonal, driven by weather patterns, industrial consumption, and power generation.
WTI is heavily influenced by geopolitical events and Exploration and Production (E&P) activity. Demand ties closely to economic growth, travel, and industrial activity. Since becoming a net petroleum exporter in 2020, low oil prices no longer directly boost US GDP.

Current Market

Futures for WTI are currently flat in the $59-62 per bbl range through 2030. Spot prices for WTI fell 20% in 2025 due to increased US shale production, OPEC adding 400,000+ barrels/day, softening economic forecasts, and production outpacing consumption. This led to the second-largest global oil inventory build since 2000 (after 2020).
Please refer to our Crude Awakening article for more details on the market dynamics involving contango and backwardation conditions in oil and other markets.

Source: CME

Running Venezuela: Why Heavy Crude Won't Lighten U.S. Energy Costs

Developments from Venezuela have been dominating the newscycle since the US captured its President, Nicolas Maduro, on January 3. Now that you’ve been primed on oil market fundamentals, let’s dig into the potential impacts of further US involvement in Venezuela’s oil industry. TL;DR: US involvement in Venezuela will not have short-term effects on US oil or energy markets due to Venezuela’s production capacity and uncertain future.

Venezuela’s total production, today, is about 1% of global oil and 8% of total US production.
From 2019 through 2022, the US did not import any oil from Venezuela due to US-imposed sanctions. In 2023 and 2024, the US imported 48 million and 84 million barrels of oil , respectively. Venezuela otherwise has no physical or financial ties to the major underpinnings of US energy production.
Oil industry leaders will have to make significant investments in order to extract less desirable “heavy” Venezuelan crude oil. Around 75% of Venezuelan oil is heavy oil. According to S&P, the breakeven price for heavy oil is around $63-$70 per barrel, whereas the market price for a barrel of oil is $58.
According to Reuters, Exxon Mobil has already stated it would not be interested in making any investments. CEO Darren Woods asserted that the Latin American country was currently "un-investible" on both commercial and legal grounds.
Despite significant reserves, extracting significantly more oil from the nation requires a long-term investment. The near term focus will likely be on assessing existing infrastructure to regain some of the capacity lost in recent years.

Venezuela's oil output is too low to significantly impact US energy markets. While its proximity to Gulf Coast refineries is an advantage, its crude is mostly heavy and costly to extract. Before sanctions, the US imported large amounts of Venezuelan heavy crude; Canada has since replaced these supplies.
The Trump Administration's short-term stated goal is to obtain 30-50 million barrels of Venezuelan heavy crude, the revenues ($1.8-3 billion) from which would be controlled by the Administration. The Administration hopes US oil companies will lead the investment, but they may be hard-pressed to find partners willing to do more than ship and remarket existing supply. Currently, Chevron, the second-largest US oil producer, is the only American company still operating in Venezuela. Thanks to specific U.S. government licenses that exempt it from broader sanctions, Chevron produces 240,000 barrels per day (about 25% of Venezuela's total output) through long-standing joint ventures with state-owned PDVSA. However, further US investment is complicated by the fact that ExxonMobil and ConocoPhillips have outstanding claims against Venezuela for billions of dollars in assets confiscated two decades ago.
Other oil companies may not want to invest so much money in a region that carries additional risks, at a time when the price of oil has dropped from $70 to $58 per barrel in just a year.
Oversupply will only exacerbate this trend. Lower oil prices have had a significant market impact, as 22 public U.S. producers excluding Exxon and Chevron—cut capital spending by $2 billion. (See chart below)

Source: Reuters

“We take a very long-term perspective,” Exxon’s CEO Darren Woods said. “The investments that we make span decades and decades. So, we do not go into any opportunity with a short-term mindset.” This perspective provides a reality check for energy buyers speculating on future costs: US involvement in Venezuela is not a real energy play. Venezuela's output is a drop in the bucket - too small and uncertain to move the needle on US oil or gas prices and not a market-mover.

Flexible Datacenters in PJM: Lighten the Load

Stop us if you’ve heard this before - last month, PJM’s capacity auction hit a record high for the third year in a row. The auction for 2027/28 cleared at the price cap of $333.44/MW-day, marginally higher than the previous year’s $329.17/MW-day cap, but still not great news for ratepayers. Late breaking reporting indicates that the price floor/cap mechanism used by PJM, which has helped reduce capacity costs by over $13 billion over the past three years, may get extended to the 2028/29 and 2029/2020 delivery years. With that auction scheduled for the beginning of July, we’ll look at the key factors that will determine whether or not PJM can right the ship in the coming months.

Source: PJM

As charted above, the annual cost of the 2027/28 auction was $16.4 billion and will lock in a higher load cost for yet another year. The total procured capacity from the auction was also 6,517 MW below the RTO Reliability Requirement according to the PJM Base Residual Auction Report. This deficit signals that PJM does not have enough capacity to prevent a one-in-ten year power outage due to loss of load. Along with massive interconnection backlogs, data centers are the main drivers.
Of the $16.4 billion total capacity auction cost, $6.2 billion, nearly 40%, is associated with projected new data center load. In our last update, we mentioned that it’s going to take some heavy-handedness to pull PJM out of its current capacity mess. A day after the PJM auction closed, FERC assumed that role, issuing an order directing the Grid Operator to create new rules governing the interconnection of data centers.
A target of the FERC Order, which we’ve discussed in previous newsletters, is the implementation of flexible data centers. A flexible data center, simply put, can either curtail operations or supply its own power and is designed to relieve strain during peak grid demand periods. With most data centers still in early development, PJM has the opportunity to require them to implement flexible energy solutions for grid interconnection, even before firm transmission service is available. As it stands, PJM has not developed the regulatory pathways to support flexible interconnection, and the recent FERC order will require them to do so.
Utilities such as Camus Energy and Encoord have helped offer a blueprint for a scalable solution. Their Flexible Data Centers study, released in December, notes that flexible grid connection is attainable by requiring data centers to have both firm and conditional firm service, where grid power can be used in normal conditions and on-site or co-located resources must be used during peak events. Another key piece to the puzzle is bring-your-own-capacity (BYOC) arrangements, where data centers utilize PPAs, VPPAs, or on-site resources rather than waiting in the interconnection queue for new transmission or generation to become available.
If PJM is able to implement its own version of these solutions, there’s potential to effectively flex off over 30% of the planned capacity, which would help maintain reliability while relieving ratepayers from the burden of continuously escalating capacity costs. From the hyperscalers’ point of view, developing on-site solutions could allow them to get up-and-running 3-4 years faster than if they had to wait in the queue.
Flexible energy providers, including Veolia’s own Flexible Energy Solutions Group, are preparing their systems to better coordinate load, curtailable and firm, and real-time generation data so that large loads can comply with a forthcoming interruptible transmission tariff.

New Year, New England, New Challenges

ISO New England is the independent entity responsible for the reliable operation of the bulk power grid, administration of wholesale electricity markets, and power system planning for the six New England states. Its primary functions are to balance electricity supply and demand in real time, ensure grid stability, and set wholesale electricity prices through competitive markets. ISO-NE is actively updating its market design to accommodate evolving infrastructure and the clean energy transition. Let’s review a couple of key updates.

DASI Program Costs Soar, Linked to High Energy Prices

Launched in March 2025 to replace the Forward Reserve Market, the Day-Ahead Ancillary Services Initiative (DASI or DAAS) ensures grid reliability but has come at a significant cost, as we covered last quarter. DASI introduced Flexible Response Services (FRS) and Energy Imbalance Reserves (EIR), requiring generators, demand response, and dispatchable load to bid into the Day-Ahead Market for transparent pricing and improved system planning. Since launch, 9-month DASI costs have totaled approximately $602 million, far exceeding ISO-NE’s original $135 million annual estimate.
DASI settlements closely track wholesale energy prices, rising sharply when Day-Ahead LMPs exceed $60/MWh. Weekly DASI rates have ranged from $0.56/MWh to $22.30/MWh, peaking in late December 2025 when LMPs surpassed $170/MWh. With elevated winter power prices expected, DASI costs are likely to remain elevated in the near term.
Customers should anticipate the dreaded “change of law” notices that suppliers typically rely on to recover costs associated with rule changes beyond their control, the details are important. Contact your energy advisor to discuss whether such changes are permissible and reasonable, and whether rate changes are accurate. In some cases, it may be prudent to push back on suppliers.

NECEC: A Clean Energy Lifeline for New England

After a multiyear delay driven by intense political opposition, the New England Clean Energy Connect (NECEC) transmission line is expected to begin commercial deliveries of Québec hydropower to New England in January 2026. Initiated in 2017, the 1,200-MW NECEC project will supply enough clean electricity to meet roughly 20% of Massachusetts’ total power demand.
NECEC is one of the most significant infrastructure projects in ISO-New England in many years, strengthening winter reliability as regional demand grows while helping to lower wholesale energy costs. Over its first 20 years of operation, the project is projected to deliver approximately $3 billion in net benefits, with Massachusetts households expected to save $18–$20 annually on electricity bills. In addition, NECEC is estimated to reduce carbon emissions by 3.6 million metric tons per year—the equivalent of removing about 700,000 cars from the road.
Data on the NECEC transmission line is now available on the ISO New England website. As shown below, the ISO Express LMP map displays the Day-Ahead and Real-Time Locational Marginal Price data, while the External Interfaces graph shows a purple line representing the volume of imports over NECEC throughout each operating day.

Source: ISO-NE

ISO-NE Proposes Major Overhaul to Capacity Market

In collaboration with stakeholders, ISO-NE is redesigning the capacity market to enhance reliability and cost-effectiveness as the region’s resource mix evolves. The Capacity Auction Reforms (CAR) project includes two phases, both requiring FERC approval ahead of the first reformed auction in 2028, with Phase 1 now filed and an order requested by March 31. The timeline for various phases is shown below:

Source: ISO-NE

Phase 1 shifts capacity auctions to a 'prompt' one-month-ahead timeline to improve forecast accuracy, eliminate non-operational resources, and simplify participation. It also shortens the resource deactivation process from 4 years to 1, while maintaining reliability safeguards. Phase 2, planned for Q4 2026, will introduce separate summer and winter auctions to reflect seasonal demand and update accreditation to credit resources based on their actual contribution to reliability.
A new era for ISO-NE cost structuring is here. While it aims to spur innovation, it’s currently threatening to keep coming with a hefty price tag. Rest assured, we will be tracking these developments, cutting through the complexity to report on what it means for your bottom line.

Offshore Wind: Waiting it Out

In a previous article covering the rift between Pennsylvania and the PJM grid operator, our team noted “Breakups are tough; some are also expensive.” New England’s offshore wind industry has been grappling with this reality over the past year amid project suspensions, stalled negotiations, and mounting challenges from the current administration. However, this isn’t quite a breakup yet – it’s more of a “will they, or won’t they?” situation.

Before 2025, New England's offshore wind sector was poised for significant expansion. Multiple projects were planned and already underway to help the region achieve its ambitious renewable energy goals, including MA’s target of 5,600 MW of wind energy by 2027.
Several projects are under construction, partially energized, or in the case of Revolution Wind, just months away from becoming fully operational. All of these projects were dealt a major blow just before the holidays when the Trump administration suspended leases for five key projects: Revolution Wind and Vineyard Wind off the coast of MA, Coastal Virginia Offshore Wind, and two New York projects: Sunrise Wind and Empire Wind.
The timing proved especially devastating for Revolution Wind (704 MW), as the stop-work order arrived during a critical construction phase – with the project 90% complete and mere weeks from delivering power to the grid. The Trump administration halted the projects due to national security concerns, and the cost of delays are estimated at $1.4M per day. On January 12, a DC court approved a preliminary injunction allowing it to resume work. On January 15 it did the same for Empire Wind in New York.
The loss of Revolution Wind alone would cost New England ratepayers $500M annually. The project would provide 2.5% of all power generated across the already-constrained region; its loss could translate into electric rate increases of 5-7% starting in 2028.
New Bedford's Marine Commerce Terminal was designed to support staging, assembly, and deployment for major projects like Vineyard Wind. With the project's turbine installations nearly finished, the multimillion-dollar lease expiring in June, and SouthCoast Wind delayed by two years due to recent setbacks, the terminal is being forced to pivot to other revenue streams as developers fight stop-work orders.
Looking ahead, uncertainty deepens as contract negotiations between electric utilities and offshore wind developers have been delayed, yet again. They were originally scheduled to conclude in December, but are now extended through June 2026 – and many analysts now expect early development-stage offshore wind remain frozen for the remainder of President Trump’s term.

Source: New England for Offshore Wind, Veolia

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.

View full post