CALGARY, Alberta (Feb. 11, 2026) Enverus Intelligence® Research (EIR), a subsidiary of Enverus, the most trusted energy SaaS company that leverages generative AI across its solutions, is releasing Global Exploration Fundamentals: Green Shoots of a Recovery, a new global exploration outlook examining early signals of renewed upstream exploration activity following several years of historically low investment and drilling.
EIR finds that while global exploration and appraisal activity in 2025 remained near historical lows, long‑lead indicators such as block awards, new country entries and increased seismic surveying point to a gradual recovery forming from a very low base. Despite depressed activity levels, exploration success rates have held steady in the 30% to 40% range, underscoring a continued focus on prospect high‑grading, capital discipline and risk‑weighted exploration strategies.
“Exploration is not rebounding quickly, but the early indicators are clearly improving,” said Patrick Rutty, director at EIR.
“Given recent drilling success and diminished concerns over peak demand, the industry is reprioritizing exploration, a dynamic that should drive resource capture to relatively high levels over the next five years but does not yet negate the risk of a structural supply gap later this decade.”
Key Takeaways:
Global exploration activity remains depressed, with 2025 exploration and appraisal wells and discoveries near historical lows following the prolonged downturn that began in 2020.
Exploration success rates remain resilient at roughly 30% to 40%, even as total well counts declined, reflecting continued prospect high‑grading across global basins.
Offshore exploration accounted for more than 50% of total activity in 2025, driven by infrastructure‑led exploration and renewed focus on higher‑impact opportunities.
Supermajors and national oil companies are leading the exploration recovery, particularly in acquiring new acreage in regions where subsurface potential for giant discoveries is matched by above‑ground conditions that support faster project advancement.
Independent and junior explorers are increasing participation, signaling broader industry reengagement beyond supermajors and national oil companies.
EIR expects the slow recovery to contribute to a structural supply gap after 2030, as limited exploration today constrains future project pipelines and resource replacement.
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About Enverus Intelligence® Research Enverus Intelligence ® | Research, Inc. (EIR) is a subsidiary of Enverus that publishes energy-sector research focused on the oil, natural gas, power and renewable industries. EIR publishes reports including asset and company valuations, resource assessments, technical evaluations and macro-economic forecasts; and helps make intelligent connections for energy industry participants, service companies and capital providers worldwide. Enverus is the most trusted, energy-dedicated SaaS company, with a platform built to create value from generative AI, offering real-time access to analytics, insights and benchmark cost and revenue data sourced from our partnerships to 95% of U.S. energy producers, and more than 40,000 suppliers. Learn more at Enverus.com.
CALGARY, Alberta (Feb. 10, 2026) — Enverus Intelligence® Research (EIR), a subsidiary of Enverus, the most trusted energy‑dedicated SaaS company leveraging generative AI across its solutions, has released its latest Fundamental Edge report raising near‑term oil price forecasts amid escalating geopolitical risk while maintaining a cautious outlook as global oil inventories are expected to continue building.
EIR raised its first‑quarter 2026 Brent crude forecast to $60 per barrel, up from $50, lifting its full‑year 2026 average forecast to $58 per barrel. The revision reflects tighter near‑term crude balances driven by political instability in Iran, outages at Kazakhstan’s Tengiz oil field and weather‑related production disruptions. These factors have complicated the path to a more durable oil price recovery.
“Geopolitical risk in Iran and transitory supply outages could delay our anticipated reconciliation of elevated OECD crude and product inventories, as prices remain tolerable for U.S. producers,” said Al Salazar, director of research at EIR.
Key takeaways:
Brent crude forecasts were raised to $60 per barrel for 1Q26, lifting the 2026 annual average to $58 per barrel, driven by heightened geopolitical risk in Iran and ongoing supply outages.
U.S. crude and product inventories, excluding the Strategic Petroleum Reserve, are building at roughly 1 million barrels per day (excluding the impact of Winter Storm Fern) and stand near 1.3 billion barrels, a level last seen in early 2021.
OECD oil inventories are expected to rise 100 million to 150 million barrels above the five‑year average in the first half of 2026, increasing pressure on near‑term oil prices and futures‑curve structure.
Henry Hub natural gas prices are held at $3.60 per million British thermal units for summer 2026, though slowing Lower 48 power demand presents growing downside risk.
Title Transfer Facility (TTF) natural gas prices averaged $11.80 per million British thermal units in January, aligning with EIR’s expectation that prices will remain in a $10 to $12 range as global liquefied natural gas capacity expands.
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About Enverus Intelligence® Research Enverus Intelligence ® | Research, Inc. (EIR) is a subsidiary of Enverus that publishes energy-sector research focused on the oil, natural gas, power and renewable industries. EIR publishes reports including asset and company valuations, resource assessments, technical evaluations and macro-economic forecasts; and helps make intelligent connections for energy industry participants, service companies and capital providers worldwide. Enverus is the most trusted, energy-dedicated SaaS company, with a platform built to create value from generative AI, offering real-time access to analytics, insights and benchmark cost and revenue data sourced from our partnerships to 95% of U.S. energy producers, and more than 40,000 suppliers. Learn more at Enverus.com.
Siemens Energy said it will invest $1 billion to expand U.S. manufacturing for power-grid equipment and gas turbine components. The move is primarily driven by the rapid growth in electricity demand from data centers and AI infrastructure. At the center is Mississippi, home to what the Germany-based company expects to be its largest grid-equipment factory worldwide, scheduled for completion in 2028.
Turbine supply chain constraints remain a critical bottleneck for gas-fired generation buildout. While distributed generation solutions are gaining traction with players like GEV, Siemens is scaling large-turbine manufacturing to directly address shortages in utility-scale and firm generation capacity.
The expansion will supply the transformers, switchgear and turbine components needed to energize new AI campuses. According to Siemens, these investments will increase global turbine manufacturing capacity by up to 20%, enabling faster deployment of firm generation in regions with constrained grid capacity.
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Key Takeaways
Why is Siemens Energy investing $1 billion to expand U.S. manufacturing?
Siemens Energy is responding to surging electricity demand from data centers and AI infrastructure by scaling U.S. production of transformers, switchgear and gas‑turbine components. The expansion strengthens domestic supply chains and positions the company to support utilities and developers facing rapid load growth and strained grid capacity.
Why is Mississippi at the center of Siemens’ expansion strategy?
Mississippi will host Siemens’ largest grid‑equipment factory worldwide, slated for completion in 2028. This facility anchors the company’s U.S. expansion and will produce the high‑voltage equipment required to energize new AI campuses and alleviate congestion in regions struggling to interconnect large‑scale load.
How does Siemens’ plan address the turbine supply‑chain bottleneck?
Persistent shortages in large‑turbine components have constrained new gas‑fired generation. Siemens’ manufacturing expansion is designed to increase global turbine production capacity by up to 20%, accelerating deployment of firm generation needed to balance AI‑driven load growth and support grid reliability.
About Enverus Intelligence® | Research
Enverus Intelligence® | Research, Inc. (EIR) is a subsidiary of Enverus that publishes energy-sector research focused on the oil, natural gas, power and renewable industries. EIR publishes reports including asset and company valuations, resource assessments, technical evaluations, and macro-economic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.
This week’s energy headlines spotlight transformational U.S. shale mergers, rising production trajectories from majors, midstream expansions tied to NGL and LNG growth, and major advancements in low carbon and global LNG development. Here are five stories that stood out:
Top Stories
Devon and Coterra announce $25.5B all-stock merger Devon Energy and Coterra Energy agreed to a $25.5 billion all stock merger, creating one of the largest U.S.-focused producers. The combined company is expected to deliver more than 1.6 MMboe/d next year, with a dominant position in the Delaware Basin anchoring long term scale and efficiency.
SM Energy closes merger with Civitas, doubling footprint SM Energy finalized its merger with Civitas Resources, more than doubling its operational footprint. Pro forma production climbs to nearly 550,000 boe/d, positioning the combined company to leverage scale across multiple basins.
Chevron targets 7–10% growth in 2026 after record year Chevron projects 7–10% production growth in 2026 following record output in 2025. Growth will be driven by more than a full year above 1 MMbbl/d in the Permian as well as rising volumes from Guyana and the Gulf of Mexico.
Enterprise brings Bahia NGL pipeline online, advances multiple expansions Enterprise Products Partners placed its Bahia NGL pipeline into service, moving Permian volumes to Mont Belvieu. The company is now advancing an expansion toward 1 MMbbl/d, a New Mexico extension slated for late decade completion, and additional sour gas and Haynesville capacity supported by long term commitments.
Venture Global selects Worley for CP2 Phase 2 EPC work U.S. LNG momentum continued as Venture Global selected Worley to execute EPC work for CP2 Phase Two, moving another tranche of export capacity closer to a final investment decision. The selection marks continued commercial progress for one of the Gulf Coast’s largest proposed LNG projects.
Additional Stories
Also this week: Glenfarne secured Texas LNG financing, Liberty raised capital for distributed power, Baker Hughes increased its data center targets, Enlight advanced a major solar storage build, Treasury proposed 45Z rules, Equinor sold Vaca Muerta assets to Vista, Ørsted exited its onshore portfolio and Total Energies resumed work on Mozambique LNG.
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A major winter storm recently swept across Eastern Canada and the Eastern U.S., triggering significant turbulence in natural gas markets. Traders across North America found themselves grappling with soaring prices and, in some instances, record-setting volatility. Amidst this frenzy, Alberta’s AECO hub, Western Canada’s primary gas trading point, maintained a remarkable degree of stability. This blog aims to unpack the recent price swings, the influence of weather and the unique factors that have largely insulated Alberta from this market upheaval.
The US Natural Gas Market: A Forecaster’s Nightmare
Recent market events presented a challenging scenario for price forecasters. A sudden polar vortex, largely unanticipated, sent natural gas prices at Henry Hub, the most traded U.S. hub, soaring from about $2.80/MMBtu to $7/MMBtu in just two trading sessions (correction: it took a week). Regionally, the spikes were even more dramatic: New York gas prices surged to $61/MMBtu, while Texas saw prices hit $17/MMBtu. This volatility highlights the critical role of weather, which can skyrocket prices to levels that destroy demand or necessitate fuel switching.
The roller-coaster ride began in the fall, with traders initially anticipating a cold blast that pushed prices to $5 before weather forecasts turned bearish with projections of warmer-than-normal temperatures. The polar vortex’s unexpected arrival caught many off guard, leading to a fascinating phenomenon known as a “short squeeze.” Our team observes that most traders had positioned themselves for falling prices based on earlier weather forecasts. When the cold hit, these traders were compelled to buy back their short positions to limit losses and then take bullish positions, significantly compounding market volatility. Interestingly, this period was warmer than the previous year, yet the trading momentum still drove an unprecedented price spike.
This sequence of whiplash events shows just how unforgiving the U.S. natural gas market can be for anyone trying to anticipate price direction. Rapid swings in expectations drove equally rapid price moves, and the delayed onset of the polar vortex highlighted how even modest shifts in weather projections can skew trader positioning and set off disproportionate market reactions. Many participants had leaned bearish on the back of earlier warm forecasts, only to scramble to cover shorts as temperatures plunged, intensifying the spike.
In markets this sensitive to weather, the meaningful advantage often comes from earlier or more localized signals rather than broad consensus forecasts. In this case, Climavision’s high‑resolution point‑forecasting approach was able to highlight the potential for unusually cold conditions in key production regions several days before the cold snap developed. That kind of early indication can give market participants valuable time to reassess exposure, whether by adjusting positions, securing storage, or hedging ahead of a possible demand surge and risk of supply disruptions.
Alberta’s Unaffected Stability: A Supply Story
In contrast, Alberta’s natural gas hub remained relatively stable. We attribute this stability to the province’s robust inventory supply and surplus of gas in storage. Furthermore, Alberta has experienced largely normal winter to date, maintaining healthy storage levels since November.
The key factor insulating Alberta from the extreme price spikes seen elsewhere is the inability to efficiently transport the province’s gas to the specific markets experiencing weather-driven demand spikes. This geographical and infrastructural disconnect means that while New York faced $61 gas prices, Alberta’s abundant supply will not reach those consumers. This situation, while frustrating for some producers seeking to capitalize on high prices, results in a domestic market that is relatively less volatile compared to some of its supply-starved customers, often to the envy of Canadian producers.
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Looking ahead, we anticipate that natural gas market volatility is likely to increase, driven significantly by the ongoing revolution in North American LNG exports. The continent is effectively doubling its capacity to export gas, with projects like LNG Canada in B.C. further integrating Canadian and North American supply with global markets, particularly Asia.
This introduces a new layer of complexity. Asian gas storage capacity is roughly half that of North America, making these markets more susceptible to price shocks from weather disruptions. Consequently, any uncommitted volumes of gas that cannot land in Asia because of disruptions could ripple back and impact prices in Canada and the U.S., further exacerbating volatility.
The Canadian Producer’s Dilemma
For Alberta producers, marketers and traders, the current market dynamics present a challenge. While observing the high prices in other regions, there’s a prevailing sentiment of envy. A common narrative in downtown Calgary is the frustration over why AECO prices struggle to reach $4 or $5, even with the advent of LNG.
This blog post is based on an episode from the Calgary Eyeopener radio series, hosted by Loren McGinnis, featuring an interview with Al. You can check out the full episode here.
Key Takeaways
What caused the recent natural gas price spike in the U.S.?
A sudden and unexpected polar vortex led to a short squeeze, causing Henry Hub prices to nearly triple and regional prices in New York and Texas to surge significantly.
Why did Alberta’s natural gas market remain stable during this period?
Alberta’s market stability was due to abundant supply, ample storage and the inability to transport gas efficiently to the highly affected American markets.
How might future LNG exports impact natural gas market volatility?
Increased LNG export capacity will link North American markets more closely with Asia, whose lower storage capacity could lead to greater price volatility rippling back to North America.
About Enverus Intelligence®| Research
Enverus Intelligence® | Research, Inc. (EIR) is a subsidiary of Enverus that publishes energy-sector research focused on the oil, natural gas, power and renewable industries. EIR publishes reports including asset and company valuations, resource assessments, technical evaluations, and macro-economic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.
CALGARY, Alberta (Feb. 4, 2026) Enverus Intelligence® Research (EIR), a subsidiary of Enverus, the most trusted energy SaaS company that leverages generative AI across its solutions, is releasing Power & Renewables Fundamentals: Shifting to Stability, a new report examining how rising electricity demand, policy shifts and interconnection bottlenecks are reshaping renewable energy economics and accelerating the market’s renewed focus on grid reliability.
EIR finds that U.S. electricity load is projected to grow 34% by 2050, but renewable development is increasingly constrained by interconnection delays, accelerated tax credit phaseouts and rising costs forcing power markets to prioritize dispatchable generation and firming capacity to maintain reliability. Recent extreme weather events, including Winter Storm Fern, reinforced these structural challenges by exposing the limits of capacity that lacks firm deliverability during periods of peak demand.
“The power market is no longer optimizing for lowest marginal cost, it is optimizing for reliability,” said Ryan Luther, a director at EIR.
“Interconnection delays, policy uncertainty and higher development costs are pressuring renewable project economics, while dispatchable resources and firming technologies are being repriced as essential to keeping the electric grid stable during both normal operations and extreme weather events.”
Key takeaways:
Electricity demand is forecast to rise 34% by 2050, intensifying the need for reliable generation as data centers, electrification and industrial load growth outpace new capacity additions.
Interconnection delays now average 3.5 years, creating a structural bottleneck that slows renewable buildouts and elevates near term‑ supply risk across multiple independent system operators (ISOs).
Renewable energy economics are under mounting pressure as accelerated tax credit retirements, new tariffs and foreign entity of concern (FEOC) requirements push levelized cost of energy (LCOE) higher, with impacts varying significantly by region.
Solar transaction valuations fell sharply in 2025, with average deal multiples dropping to roughly half of the ~$1 million per megawatt levels observed since late 2024, reflecting tighter economics and policy uncertainty.
Battery energy storage retains federal tax credit support, but market saturation, lower price volatility and compliance uncertainty are narrowing opportunities, making regional selectivity increasingly critical.
Play Fundamentals is an EIR research series that dives into a key geographical basin or technology. A collective series, with each play updated annually, it includes technical research and interactive maps, investment opportunities, benchmarking, macro trends and basin analytics, empowering readers to make intelligent connections and, overall, more informed investment, operating and strategic decisions. It is considered the most in-depth research EIR offers and among the most-read analysis series in the energy industry.
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EIR research reports cannot be distributed to members of the media without a scheduled interview. If you have questions or are interested in obtaining a copy of this report, please use our Request Media Interview button to schedule an interview with one of our expert analysts.
About Enverus Intelligence® Research Enverus Intelligence ® | Research, Inc. (EIR) is a subsidiary of Enverus that publishes energy-sector research focused on the oil, natural gas, power and renewable industries. EIR publishes reports including asset and company valuations, resource assessments, technical evaluations and macro-economic forecasts; and helps make intelligent connections for energy industry participants, service companies and capital providers worldwide. Enverus is the most trusted, energy-dedicated SaaS company, with a platform built to create value from generative AI, offering real-time access to analytics, insights and benchmark cost and revenue data sourced from our partnerships to 95% of U.S. energy producers, and more than 40,000 suppliers. Learn more at Enverus.com.
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The future energy mix demands a power source that is not only scalable and low-carbon but also capable of providing true baseload, around-the-clock energy. Advanced Geothermal Systems (AGS), particularly closed-loop technology, are emerging as a compelling solution to this critical need. As the lead of the Subsurface Innovation team here at Enverus Intelligence® Research, I’ve had the privilege of exploring these advancements, including a recent conversation with Matt Toews, Chief Technical Officer at Eavor. This discussion highlighted how innovative approaches are solving the reliability puzzle and shaping the next wave of energy. Join me as we delve into the transformative potential of closed-loop geothermal and its implications for a sustainable future.
From Oil Sands to Subsurface Heat: A Transferable Expertise
The transition from traditional oil and gas to renewable energy often sparks curiosity about transferable skills, and Matt Toews’ journey is a prime example. With seven years as a reservoir engineer in the Canadian oil sands, focusing on SAGD (Steam-Assisted Gravity Drainage) operations, Matt pivoted to co-found Eavor. He emphasizes the striking parallels between SAGD and Eavor’s closed-loop geothermal approach, noting that 90% of Eavor’s staff come from oil and gas backgrounds. Both fields operate with a “resource plate” mindset, where the resource location is known, shifting the focus from exploration to deploying technology, engineering, and manufacturing to drive down costs through scale and improved operations. While SAGD injects heat into the ground, Eavor’s system extracts it, leveraging similar technical skill sets in thermal well design, long wells, thermal facilities and thermodynamic modeling.
The Eavor-Loop Advantage: Predictability and Scalability
Eavor’s closed-loop system, known as Eavor-Loop, is essentially a subsurface heat exchanger, a radiator underground that collects heat through thermal conduction from a volume of rock. Water, with specific additives, circulates through the system, passively picking up heat for use in district heating, electricity generation, or other applications. This approach aims to create a reliable, predictable, and manufactured product, much like a solar panel. A key differentiator is its ability to eliminate geological uncertainty, as it doesn’t rely on specific geological formations or a permeable reservoir. Once built, the system is designed to be highly predictable and reliable over decades, offering significant benefits such as minimal water use or loss, no fracking and no induced seismicity, which are crucial for broader stakeholder acceptance.
Germany’s Geothermal Breakthrough: A Commercial Milestone
Eavor recently achieved a significant milestone with its Geretsried project in Germany, where the first loop came online in December, generating both heat and electricity. This project was conceived as a first-of-its-kind commercial-scale demonstration, proving economic viability in Europe’s district heating market. While the journey presented considerable operational, technical, and financing challenges, Eavor successfully navigated them. Building on insights from their Eavor-Lite pilot in Alberta, which has operated for five years with less than a 1% difference between predicted and actual output, the Geretsried project goes deeper at 4.5 kilometers, featuring 3000-meter lateral lengths. It utilizes six inlet and six outlet multilaterals that intersect at the toe using magnetic ranging while drilling, a world-first technology. This advanced drilling technique has dramatically improved efficiency, reducing the time to drill the most recent legs from 100 days to as little as 8 days, a tenfold reduction that directly impacts project costs.
Operational Efficiency and Societal Impact
A notable advantage of Eavor’s closed-loop system is its exceptionally low opex. Eavor projects typically see 80-90% capex and only 10-20% opex, a stark contrast to traditional hydrothermal or EGS projects (50/50) or natural gas power plants (10% capex, 90% opex). This efficiency stems from eliminating common cost categories such as injector well redrills, large downhole pumps, and extensive water treatment, thanks to the controlled, closed-loop water chemistry. Furthermore, the system addresses public perception concerns by minimizing water loss, as low as 0.1% of daily throughput, significantly lower than open systems, and avoiding induced seismicity risks. This mitigation of environmental impacts is particularly important in densely populated European regions, where district heating, a market valued at over $40 billion annually, offers a substantial opportunity to replace coal or natural gas-fired centralized boilers.
Powering the Future: AI, Deep Drilling, and the Geothermal Holy Grail
The demand for reliable, carbon-free power is escalating, particularly from sectors like AI and data centers, with Microsoft already an investor in Eavor. While current closed-loop geothermal technology may not make a significant dent in the immediate three-year power demand, it is poised to be a major player in the 2030 timeframe. Eavor’s technology development program focuses on going deeper and hotter, with a clear line of sight to deliver electricity at competitive prices, below $100 per megawatt-hour, even in average geothermal gradients. The modular nature of Eavor’s system, allowing for scaling in smaller, manageable chunks, offers a distinct advantage over mega-projects like nuclear power plants, which often face capital overruns. The company is actively designing a drilling system capable of reaching 15 kilometers in depth, pushing the boundaries of what’s currently achievable and leveraging innovations like insulated drill pipe for active cooling in extreme temperatures. This pursuit of the “geothermal anywhere” vision represents a significant step towards a truly sustainable and dispatchable energy future.
Conclusion
The journey from oil sands expertise to pioneering advanced geothermal systems demonstrates a powerful convergence of innovation and necessity. Eavor’s closed-loop technology offers a reliable, predictable and environmentally conscious solution to the global demand for baseload, low-carbon energy. By addressing key challenges in cost, scalability and public acceptance, companies like Eavor are redefining geothermal’s potential. The path forward involves continued execution, technological refinement and strategic partnerships, but the clear line of sight to affordable, dispatchable power anywhere in the world paints an optimistic picture for geothermal’s role in our energy future.
Key Takeaways
What is the core innovation of Eavor’s closed-loop geothermal system?
Eavor’s system acts as a subsurface heat exchanger, extracting heat via conduction without requiring a permeable reservoir or significant water use, making it predictable and scalable.
How does Eavor address the challenge of high operational costs in geothermal?
By eliminating the need for injector well redrills, downhole pumps and extensive water treatment, Eavor significantly reduces operational expenditures, making its projects 80-90% capital-intensive upfront.
What is Eavor’s long-term vision for geothermal energy?
Eavor aims to deliver low-cost electricity (below $100/MWh) from geothermal anywhere in the world by developing technology to drill deeper and hotter, eventually reaching depths of 15 kilometers.
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This blog is just a preview of the insights from Graham Bain’s Innovation Underground. Explore the full series to see what’s shaping today’s energy markets.
About Enverus Intelligence® | Research
Enverus Intelligence® | Research, Inc. (EIR) is a subsidiary of Enverus that publishes energy-sector research focused on the oil, natural gas, power and renewable industries. EIR publishes reports including asset and company valuations, resource assessments, technical evaluations, and macro-economic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.
CALGARY, Alberta (Feb. 3, 2026) Enverus Intelligence® Research (EIR), a subsidiary of Enverus, the most trusted energy SaaS company that leverages generative AI across its solutions, is releasing a new report examining how Winter Storm Fern stressed Northeast power markets and highlighted the reliability role of oil- and dual‑fuel generation when natural gas deliverability tightened during extreme cold weather.
During peak cold conditions, oil and dual-fuel generation rose sharply across Northeast power markets, reaching 44% of total generation in the New York Independent System Operator (NYISO) and approximately 35% of output in ISO New England (ISO-NE), as natural gas infrastructure operated at or near full capacity and fuel flexibility narrowed. The storm period showed a clear relationship between higher oil dispatch and the highest-priced hours across multiple Independent System Operators (ISOs.)
“Winter Storm Fern reinforced a core Northeast winter reality: electric grid reliability is often constrained not by installed generation capacity, but by fuel deliverability,” said Juan Arteaga, PhD, principal analyst at EIR.
“When natural gas pipelines are fully utilized during extreme cold, oil and dual‑fuel units become the fastest and firmest source of incremental reliability, particularly during the most stressed hours.”
Key takeaways:
Oil and dual-fuel generation increased materially during Winter Storm Fern, accounting for up to 44% of total generation in parts of the Northeast during periods of peak system stress.
In ISO-NE, oil-fired generation rose from near zero to roughly 35% of total output as cold weather tightened natural gas deliverability and power prices surged.
Across multiple ISOs, the highest‑priced hours were directly associated with increased dispatch of oil and dual‑fuel resources, reflecting fuel scarcity conditions.
Natural gas infrastructure in the Northeast operated at near full capacity during the storm, limiting incremental gas burn for power generation when heating demand peaked.
Extreme winter weather events required grid operators to rely on less economic but fuel‑secure generation, underscoring ongoing winter reliability challenges for the regional power system.
EIR’s analysis leverages proprietary data and modeling, and draws from a variety of products including Enverus MOSAIC and Enverus FOUNDATIONS® – Power & Renewables.
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EIR research reports cannot be distributed to members of the media without a scheduled interview. If you have questions or are interested in obtaining a copy of this report, please use our Request Media Interview button to schedule an interview with one of our expert analysts.
About Enverus Intelligence® Research Enverus Intelligence ® | Research, Inc. (EIR) is a subsidiary of Enverus that publishes energy-sector research focused on the oil, natural gas, power and renewable industries. EIR publishes reports including asset and company valuations, resource assessments, technical evaluations and macro-economic forecasts; and helps make intelligent connections for energy industry participants, service companies and capital providers worldwide. Enverus is the most trusted, energy-dedicated SaaS company, with a platform built to create value from generative AI, offering real-time access to analytics, insights and benchmark cost and revenue data sourced from our partnerships to 95% of U.S. energy producers, and more than 40,000 suppliers. Learn more at Enverus.com.
This week’s energy headlines spotlight deepwater momentum, Delaware Basin expansion, major South Texas marketing efforts, midstream divestitures and storage growth, and rising LNG activity. Here are five stories that stood out:
Top Stories
Beacon Offshore brings Zephyrus online in deepwater Gulf of Mexico Beacon Offshore Energy placed the Zephyrus field on production, routing volumes to Shell’s Olympus platform. A second well is expected by the end of the first quarter, supporting broader Miocene development efforts as the company’s private equity sponsor evaluates a potential sale.
Matador Resources expands Delaware Basin position Matador added more than 17,000 net acres in the Delaware Basin through a series of smaller acquisitions. Stronger results in Lea County continue to be supported by longer laterals and optimized completions.
Exxon reportedly tests market interest in major Eagle Ford package ExxonMobil is exploring a potential sale of a large Eagle Ford asset package operated by XTO, according to a Reuters report. Covering roughly 168,000 net acres and about 1,000 producing wells, it represents one of the most significant South Texas offerings in recent years.
Kinder Morgan sells EagleHawk stake, advances Trident pipeline Kinder Morgan sold its minority stake in the EagleHawk gathering system for nearly $400 million while progressing the 2 Bcf/d Trident pipeline into the Port Arthur corridor. The project is designed to support rising LNG demand along the Gulf Coast.
Boardwalk Pipeline launches 10 Bcf storage expansion at Petal Boardwalk Pipeline’s Gulf South unit initiated a 10 Bcf storage expansion at the Petal complex in Mississippi. Two anchor shippers have already subscribed to most of the capacity, highlighting strong demand for flexible gas storage.
Additional Stories
Also this week: Glenfarne advances Alaska LNG, Aramco joins Commonwealth LNG, Noble grows rig backlog, ProPetro expands ProPower, FERC licenses Goldendale storage, Jupiter boosts its credit facility, EDP adds solar capacity, Lukoil sells assets to Carlyle and Chevron/NNPC appraise Awodi.
After a menu of smaller corporate transactions and asset deals in 2025, consolidation among large-cap E&Ps is back on the table with Devon Energy’s blockbuster $26 billion acquisition of Coterra Energy. The deal is comparable in size to Diamondback’s Endeavor purchase and the fourth largest upstream combination since 2020. It forms a company with a pro forma enterprise value of $58 billion. Coterra shareholders will receive 0.7 shares of Devon per outstanding share. That is around a 12% premium to the unaffected share price before rumors of the combination emerged in mid-January, but a slight discount to the company’s Friday close.
The acquisition is another example of multi-basin M&A, which has included combinations by smaller public E&Ps. That type of deal is more common as the U.S. upstream space progresses further into a multi-year consolidation cycle and opportunities to strategically add exposure to one core play have become scarce. Investors have often cast a skeptical eye towards these types of deals and panned combinations that appeared to simply be the pursuit of scale. However, the tie-up of Devon and Coterra has strategic rationale supporting it. The companies share exposure to the Anadarko and Delaware basins. The merger plan calls for $1 billion in annual synergies by year-end 2027 including $700 million in capital optimization and margin improvements. Synergies are a cornerstone of the all-equity combination and longer-term success of the deal will in a large part hinge on delivering synergy capture.
The Delaware Basin is the real prize of the deal from Devon’s perspective and the centerpiece of the combined company. The deal propels Devon from the third largest to top producer in the prolific Delaware Basin based on gross operated volumes and positions it as a top three overall Permian producer on a gross operated basis with more than 1 MMboe/d. The Delaware Basin, and particularly the northern portion located in New Mexico, holds some of the best quality rock in North America and from an investor’s perspective a company can’t have too much exposure there. It is also a hotbed for resource expansion, with Coterra one of the companies leading the way on unlocking new zones. Devon will now add this to its existing footprint in the play, and the Delaware will play a key role in delivering on expected synergies. Delaware inventory in the combined company’s portfolio far outstrips any other play. The next largest play by remaining undeveloped locations for pro forma Devon, the Williston, has less than 15% of the remaining locations of the Delaware.
Overall, Devon will have operations across six major plays including a new position in the Marcellus. No divestment target was given as part of the deal, but the combined company could capitalize on a robust market for asset sales to trim its portfolio. The scale of the Marcellus position, which contributes about 42% of Coterra’s total net production or 2 Bcfe/d, limits the pool of acquirers if that is on Devon’s list to sell. However, the quality of the inventory and unique opportunity to acquire a position of scale in northeast Pennsylvania could draw interest from large buyers. Other divestments could come from the company’s combined Anadarko Basin positions or DVN’s Eagle Ford asset. Both plays have drawn robust interest from private capital.
The combination of Devon and Coterra demonstrates that the wave of consolidation sweeping U.S. shale isn’t finished yet and the march towards fewer, larger producers feels inevitable. That said, it doesn’t necessarily presage a stampede of mergers like was seen in 2023 and 2024 when companies may have felt pressure to jump in or be left behind. With fewer obvious targets left, corporate dealmaking from here is likely a slow, methodical grind of finding the right partner at the right point in time.
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