CALGARY, Alberta (Mar. 24, 2026) — Enverus Intelligence® Research (EIR), a subsidiary of Enverus, the leading energy-dedicated artificial intelligence and data analytics company, is releasing an updated global oil outlook that lifts its Brent forecast, reflecting impacts from the US-Israel war on Iran, near‑zero flows through the Strait of Hormuz, a record G7 SPR release, and expectations for a muted U.S. production response.
EIR now expects Brent crude to average $95 per barrel for the remainder of 2026 and $100 in 2027, accelerating global stock draws and an unresponsive supply outlook.
“The world has an oil flow problem that is draining stocks. Whenever that oil flow problem is resolved, the world is left with low stocks. That’s what drives our oil price outlook higher for longer.” said Al Salazar, director of research at EIR.
“With consolidation and stricter capital discipline reshaping the shale patch, we expect a much more restrained U.S. supply response than in previous $100/bbl environments.”
Key takeaways:
Brent crude price forecasts were upgraded significantly with EIR projecting an average of $95 per barrel through 2026 and $100 per barrel in 2027, assuming the Strait of Hormuz remains largely closed for 3 months.
Each month of constrained Strait of Hormuz flows changes the EIR outlook by approximately $10-$15/bbl, highlighting the historic significance of the disruption and high uncertainty on duration.
Even with West Texas Intermediate (WTI) prices at $90–$100 per barrel, U.S. oil producers are not expected to materially increase output. EIR forecasts liquids output to grow 370 thousand barrels per day by exit-2026 and 580 thousand barrels per day by exit-2027, reflecting drilling to production lags, industry consolidation and disciplined investment.
Global oil demand growth for 2026 has been reduced to approximately 500 thousand barrels per day, down from 1.0 million barrels per day, as higher energy prices and anticipated supply disruptions weigh on global economic activity.
Cumulative global oil stock draws are estimated at roughly 1 billion barrels through 2027, with non-OECD inventories, particularly in Asia, absorbing nearly half of the impact.
The 60-day Jones Act waiver may improve short-term U.S. shipping flexibility, but its overall impact on global oil prices is limited, with broader market forces remaining the primary driver.
This EIR analysis leverages proprietary data and modeling from a variety of products including MarketView and Enverus AI.
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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.
This week’s energy headlines spotlight war-driven market volatility, operators accelerating activity, resilient Permian performance, rising U.S. upstream investment, and new non-operated development momentum. Here are five stories that stood out:
Top Stories
ProFrac: ‘A lot of calls’ as E&Ps target DUCs with war price spike The ongoing U.S.–Israel war on Iran has injected sharp volatility into global markets, prompting operators to accelerate drilled-but-uncompleted activity. ProFrac said it is “fielding a lot of calls” from producers aiming to pull forward DUC completions to capture stronger pricing, with rising demand for dual-fuel fleets amid higher diesel costs.
Methodical inventory expansion extends stable PR productivity Permian Resources highlighted the durability of its well performance across the Delaware Basin, crediting consistent bench sequencing, multi-bench co-development and incremental shifts toward longer laterals. Leadership noted that disciplined planning has kept productivity stable despite maturing development.
Repsol to spend €2.9–3.4B across the U.S. through 2028 Repsol outlined plans to allocate €2.9–€3.4 billion in U.S. upstream capital through 2028—more than 80% of its global upstream budget over the period. The company expects U.S. volumes to grow 25–30%, led by activity in Alaska, the Gulf of Mexico, the Eagle Ford and the Marcellus.
Infinity placing $550MM in notes to repay revolver after Antero Infinity Natural Resources priced $550 million in senior notes to repay borrowings tied to its recently closed Utica and midstream acquisition from Antero. The refinancing strengthens liquidity and supports continued development across its broadened Appalachia-focused portfolio.
IOGR III closes first JV development deal, for 18 wells in PRB IOG Resources III completed its first development partnership in Wyoming’s Powder River Basin. The joint venture will drill 18 horizontal wells and marks the twentieth investment for the First Reserve–backed non-operated platform.
Additional Stories
Also this week: Kinder Morgan advanced Texas Access, Mid-Ocean raised new LNG equity, SLB One-Subsea won a CNOOC subsea award, Atlas secured a Caterpillar power framework, and Petrobras expanded in the Campos Basin.
The scrapping of a planned 600 MW expansion at the Stargate data center in Abilene, Texas, serves as a reminder that large load interconnection queues continue to be inflated. OpenAI and ORCL ended talks this month on the add‑on while the existing Abilene campus continues to operate and build out. The multiyear AI infrastructure project includes plans to develop up to 4.5 GW of capacity across additional sites. As independent system operators and utilities scrutinize interconnection backlogs, more speculative projects are likely to fall away.
Enverus Intelligence® Research has extensively modeleddata center expansion potential at the project level. In our latestoutlook (Figure 1), U.S. capacity is projected to climb to roughly 50 GW by 2030, driven by a surge in hyperscaler capital spending and AI demand. The same analysis flags rising constraints: global chip supply is a near-term cap on buildouts and up to 20% of projected load may be behind-the-meter with unclear interconnection timelines. The Stargate pullback validates these constraints, while illustrating the precarious state of large load queues.
This blog offers just a glimpse of the powerful analysis Energy Transition Research delivers on the trending themes. Don’t miss the full picture.
Class VI Update 4Q25 | Incremental Progress, Persistent Delays – In this quarterly report series, Enverus Intelligence® Research provides an overview of recent changes and additions to the growing list of Class VI wells associated with CCUS project in the U.S. Leveraging the Enverus FOUNDATIONS® – Carbon Innovation Wells database, we cover new Class VI applications, changes to permit status, permit approvals and newly disclosed project details.
Time to Power | Big Generations’ Achilles’ Heel – AI-driven data center demand is creating a structural advantage for oilfield services companies and energy-as-a-service providers as legacy equipment manufacturers like GE Vernova and Siemens Energy face a 142 GW backlog. Faster, off-grid power from firms such as LBRT is drawing hyperscalers that value speed over cost, positioning OFS names trading at 6x EV/EBITDA for potential utility-style rerating.
CO2-EOR | Path to Profitable Carbon Storage – Using anthropogenic CO2 in place of natural supply allows 45Q credits to transform CO2 from a sunk operating cost into a source of revenue for permanently stored volumes. In this report, Enverus Intelligence® Research leverages our CO2-EOR cost model to analyze how converting an existing CO2-EOR operation from natural to anthropogenic CO2 impacts financial returns.
DID YOU KNOW?
MSFT’s Project Natick underwater data center proved to be up to 8x more reliable than land-based versions by using the cold ocean as a massive natural radiator, reducing energy-intensive cooling.
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.
Natural gas price volatility has shifted from a seasonal concern to a constant reality that affects every stage of the energy value chain. Ongoing global conflicts and infrastructure disruptions are creating dramatic price reversals and market imbalances that traditional strategies may not address. This discussion explores how traders and energy managers can utilize forward curves to anticipate market shifts rather than reacting to them. You will learn to differentiate between short term supply shocks and long term structural changes across various North American hubs. We focus on using a golden source of data to build reliable curves and manage volumetric exposure in an increasingly integrated global complex. By understanding the current pulse of the market, organizations can better position themselves for a volatile 2026.
The Ripple Effect of Global Events on Domestic Markets
The North American natural gas market is becoming more integrated with the global complex, meaning events in the Middle East or Europe now have direct implications for domestic pricing. Campbell Faulkner, Senior Vice President at OTC Global Holdings, notes that while traditional seasonal volatility usually involves swings of 2% to 5%, recent years have seen natural gas move significantly more. During the initial aftermath of the Ukraine invasion, prices reached nearly 12, and we recently observed front summer prices for TTF almost quadruple in just two months.
Overnight shifts, such as natural gas reaching 3.26 before settling at 3.17 for a 3.46 percent move, underscore the sensitivity of the current market. These movements are often tied to LNG offtake and international benchmarks like JKM and TTF. While domestic markets remain somewhat insulated by pipeline constraints, the growing correlation between North American instruments and global benchmarks means that an infrastructure attack or supply disruption abroad can quickly change the domestic narrative.
Watch Our Webinar Now to Build Smarter Forward Curves to Protect Margin in 2026
Data as the Foundation for Navigating Black Swan Events
Managing black swan events requires more than just a rigid understanding of historical trends. Truly unprecedented events happen naturally over time, and tools like MarketView Sphere allow professionals to track these shifts through data and analytics. Faulkner emphasizes the importance of being price naive when constructing curves, which involves providing a clear view of where transactions can occur rather than attempting to forecast where prices will go.
Using high fidelity data helps managers understand their relative position in the market and what they are trying to defend. Whether a firm is trying to protect the value of a fixed-term bond or ensuring gas delivery for a manufacturing plant, pattern recognition through charting is essential. Patterns in the data can reveal fundamental changes, such as a new compressor station build or a storage field injection, before they are fully realized by the broader market.
Structural Shifting and the Reality of Market Tightening
Daily gas consumption has seen a steep build, rising from 82 BCF per day in 2020 to a forecast of 90 BCF per day in 2025. Much of this growth is attributed to LNG offtake rather than domestic power burn, which actually sat at 31 BCF in 2020 and is projected at 30 BCF for 2025. Despite the narrative of increasing demand from data centers and artificial intelligence, the forward curves for Henry Hub do not yet show a steep contango, suggesting the market is not yet pricing in a massive supply shortfall.
The basis markets also demonstrate regional dislocations that can catch unhedged participants off guard. For example, Waha has experienced negative fixed prices because high crude oil prices, often near 100 WTI, encourage more drilling and produce associated dry gas that exceeds pipeline capacity. Conversely, hubs like Algonquin or Transco Zone 5 remain exceptionally positive due to their proximity to demand centers and LNG sensitivity.
Advancing Analytical Sophistication in Risk Management
The approach to hedging has evolved significantly over the last decade. Risk managers are now paying closer attention to long dated curves, sometimes looking as far as nine years out for planning purposes. There is a higher degree of analytical sophistication applied to curve construction, moving away from simple estimations toward models that require a high degree of fidelity.
Companies are trying to minimize hedge costs by positioning themselves more strategically along the forward curve. This requires a fundamental understanding of market heuristics, knowing where a portfolio feels comfortable or uncomfortable as term structures shift. Integrating tools like Curve Builder directly into the trade floor environment allows for the creation of complex, adjustable curves in seconds, providing a single source of truth that connects the front and back offices.
Where Do We Go From Here on Natural Gas Price Volatility?
Looking toward 2026, the only certainty is that the market will remain spicy. External factors, ranging from the timeline of Qatar rebuilding its LNG production to the reliability of domestic trains like Freeport, make it difficult to build a single definitive thesis. I recommend that energy managers focus on the numbers rather than the stories, as data remains the most truthful indicator of market direction. Success in this environment will belong to those who use sophisticated analytics to manage their book upside down and remain prepared for unexpected pricing events. By maintaining a clear view of both geographical and pipe basis, firms can leverage the current volatility to find value rather than being sunk by it.
Key Takeaways
Why are domestic gas prices sometimes insulated from international spikes?
North American markets are often restricted by domestic pipeline capacity and long term contract structures that prevent immediate price propagation from global benchmarks.
How much has total daily gas consumption grown since 2020?
Average daily consumption has increased from 82 BCF in 2020 to an expected 90 BCF in 2025, largely driven by LNG export requirements.
What causes negative pricing at hubs like Waha in West Texas?
Negative prices occur when high oil prices drive associated gas production that exceeds the available infrastructure, sending a signal to producers to shut in or divert supply.
For much of its history, success in the Eagle Ford was largely defined by what you owned. Acreage quality, early entry, and inventory depth played an outsized role in determining outcomes. Today, that dynamic has shifted. The basin continues to offer opportunity, but the data shows how differences in development design choices and redevelopment approaches are influencing economic outcomes in the Eagle Ford.
EIR’s latest Eagle Ford Play Fundamentals report (available to subscribers here) describes a mature play where high‑quality primary inventory is finite, development choices are more interconnected, and small differences in design and spacing can meaningfully affect economics. For asset teams, this places greater emphasis on planning discipline and flexibility rather than simply maintaining activity.
Before diving deeper, here are the key takeaways that frame this shift.
Key Takeaways
What changes when a basin matures and high-quality inventory tightens?
Asset teams move from maximizing activity to prioritizing decision quality, where spacing, sequencing, and development design have longer-term implications.
What is extending runway in the Eagle Ford today?
EIR’s data highlights longer laterals, selective redevelopment, and disciplined expansion as contributors to improved capital efficiency.
Why does this matter at the asset level?
In a mature basin, near-term development decisions can shape future optionality, base production stability, and capital flexibility.
Read on to find out how development design, spacing, and redevelopment choices are extending runway in a maturing Eagle Ford.
How the Data Shows Runway Is Being Extended
At current development rates, the Eagle Ford has roughly five years of remaining economically viable, high‑quality primary inventory. While this does not reflect the basin’s full opportunity set, it does narrow the margin for error by increasing reliance on development decisions outside the core of the play, where economics tend to be more sensitive. In this environment, extending runway increasingly depends on how remaining inventory is developed rather than simply how much inventory remains.
Operators are adapting development strategies in response to these constraints, with several patterns emerging across the basin.
Longer laterals are consistently associated with improved breakevens, with the latest data showing lower breakeven outcomes as lateral lengths increase across multiple subplays. In some cases, extended laterals and horseshoe designs have shifted the economic profile of acreage that would otherwise sit higher on the cost curve.
Redevelopment strategies also play a role. EIR’s data shows tight infills generating stronger value outcomes than refracs on average, underscoring the importance of spacing and well interaction considerations. That’s not to say that infills are appropriate everywhere, but it does highlight the impact that development sequencing and depletion timing can have on results.
Expansion into geologically viable areas remains part of the opportunity set, though these locations generally carry higher break–evens. As a result, these opportunities tend to require more careful planning and execution to compete for capital, and can benefit from continued improvements in capital efficiency.
Watch this short video to see scenario driven development planning in action.
From Optimization to Understanding Economic Trade-Offs
Many of the development trends visible across the Eagle Ford are often discussed in terms of optimization, but the data also illustrates how different development approaches have an effect on economic outcomes. Breakevens can differ across lateral lengths, redevelopment types, and economically viable versus geologically viable inventory, even when evaluated under the same underlying assumptions.
These differences suggest that development economics in the Eagle Ford are increasingly shaped by design and placement choices rather than by a single dominant strategy. Variations in spacing, lateral configuration, and redevelopment approach correspond to a wide spread of breakeven outcomes across the basin, highlighting that similar assets can perform quite differently depending on how they are developed.
In this context, planning becomes less about identifying one expected result and more about understanding how different development choices compare across a range of potential outcomes.
The Eagle Ford is not necessarily unique in this regard. The dynamics currently underway in the Eagle Ford are also characteristic of mature basins where inventory quality, development design, and capital discipline converge.
Across the Eagle Ford, certain development approaches stand out for their association with stronger economic outcomes outside the core of the play. Longer laterals and horseshoe wells appear to play an important role in improving economics in Tier 2 and Tier 3 acreage, where baseline returns are more sensitive. By extending effective lateral length, these designs have been linked to lower breakevens in areas that would otherwise sit higher on the cost curve.
Redevelopment choices also show meaningful differentiation. Tight infills consistently exhibit stronger economic results when compared to refracs, often with average net present value outcomes that are materially higher. While both approaches remain part of the redevelopment toolkit, the contrast in performance highlights how spacing and redevelopment strategy can significantly influence value creation at the well level.
So, in other words, runway can still be extended but doing so depends on thoughtful, flexible development planning – especially in Tier 2 and 3 acreage. In a mature basin, the ability to apply the right combination of lateral design, spacing, and redevelopment strategy can meaningfully influence value creation, allowing a broader set of operators to improve performance and extend the productive life of their assets.
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.
The transition toward a decentralized grid has moved beyond localized experiments into a coordinated regulatory and technical effort to harness the sleeping giant of residential capacity. Across North America, Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) are currently implementing framework changes to comply with FERC Order 2222. By aggregating behind-the-meter (BTM) resources, such as batteries, EVs, and smart thermostats, these operators can create flexible, dispatchable reserves that stabilize the grid more cost-effectively than traditional gas-fired peaker plants.
ISO Deep Dives
As of early 2026, the U.S. Virtual Power Plant (VPP) landscape is no longer a monolith of pilot projects but a fragmented map of varying regulatory maturity and technical philosophy. While FERC Order 2222 provides the federal mandate for market access, the actual execution has diverged based on regional grid needs, some ISOs prioritize summer-peak load shedding to prevent blackouts, while others are redesigning their entire wholesale stack to treat thousands of home batteries as year-round virtual power plants. The result is a patchwork where a residential battery in California is a sophisticated market-aware asset, whereas the same battery in the Midwest might still be restricted to basic emergency response.
The table below summarizes where each major ISO stands today—moving from the most mature markets to the developing frontiers where full integration is still years away.
How Major ISOs Compare on VPP Readiness
Independent System Operator
Regulatory Status
Key Programs & Pilots
Expected “Go-live”
CAISO
Advanced
DSGS, ELRP, CalReady
Active
NYISO
Advanced
DER and Aggregation Model
Late 2026
ERCOT
Pioneering Pilot
ADER Pilot Phase 3, RDR Program
Active (Pilot)
ISONE
Progressing
Connected Solutions, FCM-DER integration
Late 2026
PJM
Accelerating
Capacity*Connect, Leap Partnerships
Feb 2028
SPP
Developing
Compliance target Q3 2025
Late 2026
MISO
Delayed
Implementation target 2029
2029-2030
CAISO: The Global VPP Benchmark
California leads the world in distributed flexibility, with over 42 GW of VPP capacity currently enrolled as of March 2026. The state has successfully moved beyond emergency only demand response to a fully integrated market model where tens of thousands of homes act as a single, dispatchable resource. The Demand Side Grid Support (DSGS) program and the Emergency Load Reduction Program (ELRP) have aggregated more than 95,000 batteries through partnerships with providers like Sunrun, Tesla, and Lunar Energy. The focus this year is the full implementation of Order 2222 enhancements, which aim to further lower the barriers for multi-node aggregations. This allows a single VPP to span across different geographical areas within California, providing even greater scale and flexibility to the CAISO market.
ERCOT: The Reliability Challenger
Texas has moved past the experimental stage, with the ADER Pilot now supporting up to 160 MW of capacity as of March 2026. Leveraging the Aggregate Non-Controllable Load Resource model, ERCOT allows for blocky participation in ECRS and Non-Spin markets. ERCOT’s VPPs are increasingly focused on battery-only aggregations and third-party QSEs that can bypass traditional utility (LSE) boundaries, providing a fast-tracked path for companies like Tesla and Sonnen to provide grid-scale support.
NYISO: The Separately Metered Pioneer
New York is currently in the middle of a massive transition, phasing out its old demand response programs (like DSASP) in favor of the new DER & Aggregation Participation Model which became fully operational in 2024. This is currently the most mature model for Behind-the-Meter (BTM) resources. Aggregations can now “dual participate,” meaning they can sell capacity to the wholesale market while simultaneously participating in utility-level programs like the Commercial System Relief Program (CSRP). As of 2026, the 10 kW minimum size for individual resources remains a point of contention, as it effectively excludes many single-family residential batteries. However, NYISO is under a FERC mandate to resolve these “small resource” barriers by December 31, 2026.
ISONE: The Seasonal Capacity Leader
ISO New England is using 2026 as a “Go-Live” preparation year for its full Order 2222 integration, with a specific focus on making the capacity market more accessible for seasonal storage. In a major move for 2026, ISONE is transitioning to Prompt Auctions. Instead of requiring VPPs to commit three years in advance, they can now clear the market just months before the Capacity Commitment Period. This is a massive win for aggregators who struggle with the high customer churn of a three-year lead time. While the wholesale rules are finalizing, the state-level Connected Solutions program is already a powerhouse, with over 570 MW of distributed storage (mostly in MA and CT) providing a “shadow VPP” that the ISO is now working to bring into the formal energy market.
PJM: The Capacity Market Shift
PJM uses the DER Aggregator Participation Model, requiring aggregations to be at least 100 kW. A major hurdle remains the “double counting” rules between wholesale capacity payments and state-level retail incentives. While initially slated for early 2026, PJM recently pushed its full Order 2222 implementation to February 2028 to resolve complex multi-nodal aggregation issues. However, state-level activity is filling the gap. Under the 2025 CRGA Act, Illinois launched utility-aggregator VPPs starting this spring to specifically target PJM’s high capacity prices.
MISO: The “DEAR” Framework
MISO is operating on the longest timeline, with full market integration of Distributed Energy Aggregated Resources (DEAR) not expected until 2029-2030. MISO is currently rolling out a limited-scale participation model for “Type I” resources (simpler demand response) to gain operational experience. A high-profile 2026 docket in Minnesota is pitting Xcel Energy’s utility-owned 200 MW battery plan against third-party VPP aggregators, a case that will likely set the precedent for how BTM storage is treated across the MISO footprint.
SPP: Bridging East and West
SPP is in the final stages of its market implementation, targeting late 2026 for full DER aggregation. SPP is currently prioritizing the integration of “High Impact Large Loads” (data centers) and using VPPs as a “non-wire alternative” to manage the sudden 14-18% demand surges seen in the Great Plains. The biggest story for SPP in 2026 is its expansion into the Western Interconnection. This creates a unique opportunity for VPPs to trade flexibility across the “seams” of the eastern and western grids.
The Major Players in Vertical Integration and Market Strategy
NRG Energy: The Vertical Integration Leader
NRG’s acquisition of Vivint Smart Home positions it as the premier vertically integrated player in the VPP space. By owning the security system, the thermostat, and the retail energy contract, NRG controls the entire energy stack of the home. In February 2026, NRG reported exceeding its Texas residential VPP target by 10x, reaching 150 MW of curtailable capacity. They are now vertically integrating these assets with their newly acquired CPower platform to manage both residential and industrial flexibility.
Tesla: The Software Sophisticate
Tesla remains the most technologically advanced vertical player. Through Tesla Electric, they act as a retail provider in Texas and California, using their Autobidder software to manage over 3 GW of assets globally. Tesla owners often see the highest real-time payouts because the company bypasses third-party aggregators to bid directly into the wholesale market.
Vistra (TXU Energy): The Simplified Retailer
Vistra utilizes a simplified Battery Rewards model to drive mass adoption. By offering fixed incentives (e.g., $100 every six months) rather than complex market-based math, they have captured a massive segment of casual users. They use the Kraken AI platform to orchestrate these assets as a hedge against ERCOT price spikes.
Sunrun & Sunnova: The Fleet Owners
These companies dominate through sheer volume of leased hardware. Sunrun (partnered with Lunar Energy) focuses on Home-as-a-Service, while Sunnova has pioneered VPPs in high-resilience markets like Puerto Rico. Their advantage lies in their sticky long-term leases, which provide a guaranteed pool of capacity for ISO-NE and CAISO programs.
Lunar Energy & Kraken: The Infrastructure Layer
These are the Grid OS providers. Lunar Energy focuses on hardware-software retrofits for solar orphans, while Kraken licenses its AI dispatch software to traditional utilities like National Grid and NRG to help them manage the transition to decentralized power.
Technical Optimization: AI, the Spatial Web, and IEEE 2874
The Department of Energy (DOE) targets 80-160 GW of national VPP capacity by 2030. This scale could save approximately 10 billion in annual grid costs by avoiding the construction of expensive transmission upgrades or carbon-intensive peaking plants.
The primary barrier to scaling these models is the lack of technical interoperability. The newly ratified IEEE 2874-2025 Spatial Web standard (approved May 28, 2025) provides a public imperative framework to solve this. The standard introduces the Hyperspace Modeling Language (HSML) and Hyperspace Transaction Protocol (HSTP). These protocols allow hardware from different manufacturers (e.g., a Tesla battery and a Nest thermostat) to talk to a VPP platform in a unified semantic language. This enables the creation of digital twins of the power grid, allowing ISOs to coordinate distributed assets across load zones without the telemetry burden that hindered early pilots.
The integration of Active Inference AI (based on the Free Energy Principle) allows intelligent agents to manage local energy resources autonomously. Active Inference can reduce telemetry data requirements by up to 90% by performing local optimizations at the edge and only reporting high-level state changes to the ISO. These agents are specifically designed for decision-making under uncertainty, handling the fluctuations of solar generation and occupant behavior in real-time.
As major grid operators like CAISO and ERCOT transition from pilots to permanent programs, the focus will shift toward standardized governance and the widespread adoption of the IEEE 2874 standard to ensure that every home can become a modular, resilient pillar of the global energy future.
While virtual power plants expand what the grid can do with distributed assets, interconnection queues continue to define which new grid-scale projects move forward, making queue dynamics a critical piece of the broader market picture, as detailed in our 2026 Interconnection Queue Outlook.
Geothermal power developer Controlled Thermal Resources (CTR) is moving into the public market. The company behind the Hell’s Kitchen geothermal and lithium project in California’s Imperial Valley has agreed to a $4.7 billion special purpose acquisition company merger with Plum Acquisition Corp. IV, paving the way for a Nasdaq listing. The deal, expected to close in 2026, will fund first-stage construction of what is regarded as one of the most advanced integrated geothermal and critical minerals developments in the United States. CTR is not alone. Fervo Energy filed a confidential initial public offering (IPO) registration in January, signaling a potential listing as early as this summer, just ahead of first power from its 500 MW Cape Station project in Utah.
Hell’s Kitchen’s position in the Imperial Valley places it within one of the most favorable levelized cost of energy (LCOE) ranges for next‑generation enhanced geothermal systems (EGS) (Figure 1), a key advantage for CTR as it scales the project. The integrated lithium production further strengthens its economics by adding a high-value revenue stream, effectively lowering the cost of delivered power. The combination of strong resource quality and dual commodity output is a major reason investors are treating geothermal’s newest entrants as serious contenders in a rapidly expanding market. With ORA already public, Controlled Thermal Resources is now heading to Nasdaq and Fervo pursuing an IPO, the number of publicly traded geothermal companies is set to triple, underscoring how quickly the space is maturing.
This blog offers just a glimpse of the powerful analysis Energy Transition Research delivers on the trending themes. Don’t miss the full picture.
Class VI Update 4Q25 | Incremental Progress, Persistent Delays – In this quarterly report series, Enverus Intelligence® Research provides an overview of recent changes and additions to the growing list of Class VI wells associated with CCUS project in the U.S. Leveraging the Enverus FOUNDATIONS® – Carbon Innovation Wells database, we cover new Class VI applications, changes to permit status, permit approvals and newly disclosed project details.
Time to Power | Big Generations’ Achilles’ Heel – AI-driven data center demand is creating a structural advantage for oilfield services companies and energy-as-a-service providers as legacy equipment manufacturers like GE Vernova and Siemens Energy face a 142 GW backlog. Faster, off-grid power from firms such as LBRT is drawing hyperscalers that value speed over cost, positioning OFS names trading at 6x EV/EBITDA for potential utility-style rerating.
CO2-EOR | Path to Profitable Carbon Storage – Using anthropogenic CO2 in place of natural supply allows 45Q credits to transform CO2 from a sunk operating cost into a source of revenue for permanently stored volumes. In this report, Enverus Intelligence® Research leverages our CO2-EOR cost model to analyze how converting an existing CO2-EOR operation from natural to anthropogenic CO2 impacts financial returns.
DID YOU KNOW?
The U.S. has more identified geothermalpower potential than the combined installed capacity of its entire nuclear fleet.
Key Takeaways
Why does CTR’s public listing matter for geothermal?
CTR’s $4.7 billion SPAC merger signals that geothermal is moving from niche to investable at scale. Public market access provides the capital needed to fund first-stage construction of Hell’s Kitchen and validates geothermal as a credible baseload power solution alongside other energy assets.
What differentiates the Hell’s Kitchen project economically?
Hell’s Kitchen sits in one of the most attractive cost ranges for next-generation enhanced geothermal systems. The addition of integrated lithium production creates a second revenue stream, effectively lowering the cost of delivered power and strengthening project economics compared to power-only developments.
What does this mean for the broader geothermal market?
With ORA already public, CTR heading to Nasdaq, and Fervo Energy preparing an IPO, the number of publicly traded geothermal companies is set to triple. This marks a clear inflection point where investor interest, technology readiness, and project scale are aligning.
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 Appalachian outperformance, rapid shale growth, strategic portfolio reshaping, expanded midstream control, and momentum toward a new U.S. LNG export build. Here are five stories that stood out:
Top Stories
EQT logs record D&C pace as compression lifts output EQT set new drilling and completion records, cut well costs by 13% year-over-year and exceeded sales expectations with compression upgrades that boosted base production. The performance reinforces EQT’s position as the region’s productivity leader.
Infinity to hike output 70% in 2026 after 46% growth in 2025 Infinity expects production to rise about 70% in 2026 after a nearly 50% jump last year, driven by extendedreach laterals and rapid cycle times across the Marcellus and Utica. Recent acquisitions from Antero support the program, with management emphasizing efficiency as the key enabler.
TXO & Exxon selling Permian-San Juan JV Cross Timbers for $200MM TXO’s Permian–San Juan joint venture, Cross Timbers Energy, agreed to sell assets for $200 million to multiple private buyers. TXO anticipates roughly $100 million in net proceeds, allowing it to retire a deferred payment tied to its Williston acquisition and refocus drilling on core basins.
EQT increases MVP stake, upsizes Clarington Connector EQT increased its stake in MVP and the MVP Boost expansion, strengthening its position in a transmission corridor that moved more than 2.1 Bcf/d during peak January storm demand. The company also upsized its Clarington Connector to serve rising Midwestern and datacenterdriven gas markets.
Glenfarne brings in Kiewit for EPC of 4 mtpa Texas LNG Glenfarne executed a lumpsum turnkey EPC agreement with Kiewit for its 4 mtpa Texas LNG project. Backed by a $5.7 billion financing package and fully contracted capacity, the project moves closer to FID and further positions Brownsville as a growing U.S. LNG export hub.
Additional Stories
Also this week: SLB OneSubsea agreed to acquire Envirex Group, Baker Hughes issued notes to support its Chart Industries acquisition, Hydrostor partnered with Hatch on the Willow Rock storage project, Energean entered Angola through a Chevron deal, and TotalEnergies brought its Lapa South West tieback online in Brazil.
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The recent escalation in the Middle East has triggered the most significant disruption to energy flows in decades. With key shipping lanes facing near complete interruptions, the global market is grappling with a massive supply shock that fundamentally changes expectations. We aim to quantify the scale of these outages and evaluate the potential economic consequences for global markets. Our team at Enverus Intelligence® Research (EIR) is monitoring how this conflict reshapes the view of oil and gas availability. This post examines the constraints on strategic reserves and the limitations of North American production responses in the face of historic volatility. Here, you will gain a clearer understanding of why this event is significant and what it means for long-term energy security.
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Current reports suggest that approximately 6 million barrels per day of production are offline due to damage and force majeure. The impact on the Strait of Hormuz is even more pronounced, as flows have dropped from the usual 15 – 20 million barrels per day to only 5 million barrels. We observe that some tankers are attempting to bypass detection by turning off transponders during night transits to move oil through the region. Meanwhile, the complete shut-in of LNG has caused gas prices to surge between 60% and 70% compared to pre-war levels. Brent price volatility has been unprecedented, with prices holding near $90 as the market struggles to assess the true impact of a 15–20 MMbbl/d transportation outage and a 6–7 MMbbl/d supply outage. The uncertainty is compounded by the fact that there is little clarity in how long these disruptions will persist.
Moreover, market analysts typically scrutinize annual supply shifts on the order of 1 million barrels per day, so a disruption of this magnitude is several times more impactful by comparison.
Economic Implications and Price Sensitivity
We can size up the potential impact on the global economy by looking at historical analogs like the invasion of Ukraine. That event took one percentage point off global GDP growth. The current situation depends heavily on duration, but the price sensitivity is clear. We estimate that a 10-day outage of 15 million barrels per day is worth roughly $10 on the price of oil. If the outage extends to 20 days, the impact could reach $20 on the price. This creates a high level of uncertainty for global markets and emerging economies in particular.
Strategic Reserves and Supply Constraints
Geographic Mismatch of Strategic Reserves
G7 leaders are evaluating the use of strategic oil reserves, but the decision making calculus is complex. We note that most Strategic Petroleum Reserves easily serve the Atlantic Basin, while the current shortages are primarily a Pacific Basin problem affecting Asian refiners. It would likely take 30 to 45 days for released reserves to reach those markets, meaning they cannot provide an immediate fix for shortages in Asia. This geographic mismatch limits the effectiveness of strategic releases in the short term. The problem is not necessarily a North American supply issue but a delivery issue for emerging markets.
North American Production Constraints
North American producers face significant hurdles in ramping up production to fill the global gap. Transportation constraints and a new era of capital discipline among public companies mean that production cannot surge overnight. Even if companies invest in new wells today, it takes at least six months before that production turns around. We do not expect US shale or Canadian producers to change the global supply situation in the immediate future.
Industry Adaptation and the New Normal
The Alberta energy sector remains heavily focused on securing revenue through strategic hedging amid the current volatility. Producers are increasingly inclined to lock in forward prices, which today offer roughly a $20/bbl uplift compared with pre‑war levels. This dynamic likely contributed to the rapid pullback from prices above $100/bbl at the start of the week, as increased hedging activity and profit‑taking placed downward pressure on the market.
Long Term Energy Dynamics
Looking ahead, we expect this crisis to refocus global attention on energy security and the resilience of domestic supply chains. For Asian markets, many of which faced severe LNG shortages during the disruption, this could even prompt a renewed reliance on coal, given its availability and lower vulnerability to geopolitical chokepoints. At the same time, persistently elevated gasoline prices may accelerate consumer interest in electric vehicles, particularly in regions seeking insulation from oil‑price volatility.
A return to normal market conditions remains challenging. Security risks continue to undermine confidence in long‑haul energy transportation. Such risks could embed a structural risk premium into oil and gas prices for the next five to ten years.
Ultimately, consumers and governments that have experienced interruptions to reliable energy flows are likely to prioritize energy sources they can control domestically, reinforcing a broader global shift toward localized and resilient supply options.
Key Takeaways
What is the current impact on oil flows through the Strait of Hormuz?
Daily flows have dropped from a typical range of 15 to 20 million barrels to just 5 million barrels.
Why can’t North American producers immediately fill the supply gap?
Logistics constraints and an approximate six-month lag from investment to production lag prevent an immediate increase in supply.
How does this conflict affect long term energy dynamics?
The Middle East energy disruptions intensify the global focus on energy security and domestic resource development.
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.
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 (Mar. 11, 2026) — Enverus Intelligence® Research (EIR), a subsidiary of Enverus, the leading energy data analytics platform, has released an International M&A Review examining how global resource scarcity is reshaping upstream deal activity outside the U.S. and Canada.
International upstream mergers and acquisitions remained subdued for the second year, totaling $18 billion in 2025, essentially flat year over year and well off the historical annual average of $60 billion. Limited transactable high-quality resource and lower oil prices in 2025 are factors constraining deal flow. Despite subdued activity, select regions including Latin America continued to attract buyers.
“International M&A is being shaped less by appetite and more by availability,” said Andrew Dittmar, principal analyst at Enverus Intelligence® Research. “With opportunities to buy into high-quality and scalable development projects scarce, majors have pulled back significantly from the M&A market and focused on organic expansion. Independent and private buyers have stepped in to acquire the mature assets and smaller interests these firms are meanwhile shedding.”
Latin America accounted for half of announced international deal value in 2025, led by continued consolidation in Argentina’s Vaca Muerta shale and ongoing portfolio repositioning in Brazil. Argentina recorded its most active year for upstream M&A since 2014 as regional specialists expanded positions following exits by international oil companies. Despite economic inventory, the scale of the interests held by departing IOCs were likely viewed as too small for a core holding in their global portfolios. In Brazil, majors and national oil companies continued to divest mature offshore assets to domestic operators while selectively increasing exposure to high-quality deepwater developments. Africa also remained a meaningful contributor to global activity, often involving E&Ps cycling out of mature assets to fund higher impact development programs in the Atlantic Margin.
Since early 2024, public independents and private E&Ps like key Vaca Muerta consolidator Vista Energy have accounted for more than 70% of acquisition value internationally. Rare examples of majors stepping into deal markets during the last few years include Chevron’s purchase of Hess in 2023, which focused on its Guyana interests and TotalEnergies asset swap in Namibia’s Orange Basin late last year.
Private equity participation in non-North American upstream M&A has also retreated with European investors pivoting toward power and low-carbon investments. That dynamic has further concentrated international dealmaking among regionally focused operators. A possible return of private equity money could come from U.S. based firms pursuing deals abroad as attractive acquisition opportunities domestically have dwindled and high competition raises asset prices.
Valuation metrics disclosed a two-speed market where weaker near-term crude pricing during 2025 and more deals focused on mature assets or situations involving distressed sellers reduced production and cash flow metrics. That was particularly true for oil-weighted assets. Buyers have been cautious about near-term cash flow quality, focusing closely on operating costs and end-of-life liabilities.
At the same time, reserve-based valuations have shown greater resilience. Despite wide dispersion across regions and asset types, pricing for quality reserves has generally held up better than flowing production metrics would suggest. This highlights a market that continues to value duration and development optionality, even as it discounts late-life barrels.
Looking forward, international upstream M&A is likely to remain subdued unless additional development-stage resources come to market through farm-downs, partial stake sales or broader portfolio reshaping. Regulatory clarity will be a key swing factor. Jurisdictions that improve fiscal stability, streamline approvals and provide greater certainty around transferability are more likely to convert policy reform into transactions and additional invested capital.
The recent geopolitical-driven run-up in oil prices has also injected both potential momentum and volatility into the market. Higher crude prices improve near-term cash flow to fund M&A and make a wider range of assets economically attractive as acquisition targets. However, price uncertainty can widen bid-ask spreads and lead to a downturn in transactions until stability returns.
“The current injection of massive supply uncertainty into crude markets complicates negotiations by widening the bid-ask spread,” said Dittmar. “That is particularly true in the current market, where the duration of supply disruptions and longer-term impact on crude is opaque. But if higher prices prove durable it will cause a resurgence of interest in expanding global supply, unlocking more development projects and broadening buyer appetite. That ultimately supports stronger and more sustained deal flow.”
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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.
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