Mineral Management

The Hidden Inventory in Mineral Markets

Over the last three years, mineral investors have watched consolidation squeeze the deal market tighter each quarter. According to Enverus Intelligence® Research, Viper Energy has captured 63% of all publicly disclosed mineral and royalty deal value since 2023 (Available to EIR Subscribers). The quality deals disappear faster, competition climbs, and prices follow. According to Enverus Intelligence® Research, Permian mineral acreage pricing has increased significantly over the past three years. And that’s just for the deals buyers can actually see (Available to EIR Subscribers). Overcoming the competitive edge of large buyers means smaller players will need to be nimbler and more creative by finding hidden mineral opportunities and acquiring off-market mineral rights.

The Deal Flow Problem Nobody Talks About

Here’s what mineral buyers don’t say in earnings calls. A lot of deals never make it to the market at all. This off-market reality is where a hidden mineral inventory exists.

Some mineral interests trade hands quietly between investors. Others sit on balance sheets where owners don’t actively market them, while some get bundled into large acquisition packages where a buyer must buy the whole thing just to get the acreage they want. The fragmentation across mineral ownership is significant, and it creates a visibility gap that traditional deal sourcing channels simply can’t address.

When you rely on brokers, you see what brokers want you to see. That’s not a comprehensive market. It’s a curated subset of it. And by the time a property hits a broker’s desk, three other acquisition teams usually know about it already. Finding hidden mineral opportunities and identifying off-market mineral rights earlier is the advantage.

Mineral owners sense this too. Small interest owners who might sell on the right terms don’t want to pay broker commissions on something they inherited thirty years ago. Sophisticated operators who have assembled mineral positions aren’t going to look for them unless they need to. The result is a massive hidden mineral inventory of mineral interests that would transact under the right circumstances but never appear in deal flow, creating real mineral acquisition opportunities for buyers with better visibility.

Consolidation Is Rewriting the Game

Centralized deal access creates a permanent competitive advantage. The buyers who can see more opportunities, in more places, with better production data attached are the ones closing more deals at better terms. Everyone else is reacting to what others are selling. Consolidation has made that advantage even more pronounced, especially for acquiring off-market mineral rights in secondary basins and within hidden mineral acreage.

This concentration creates feedback loops. Big consolidators can afford to pay premium prices in the Permian and still generate accretive returns because they have scale. Mid-size buyers get priced out or forced into secondary basins. Smaller buyers leave the market entirely. The consolidation accelerates. Inventory gets absorbed faster, but the hidden mineral inventory still exists off-market for those focused on mineral rights acquisition outside the obvious channels.

Enverus Intelligence® Research tracking reveals that total disclosed mineral and royalty deal value dropped to $360 million in Q1 2026, a level that would have been quiet in 2022 but reflects a market that’s really tightened.

The Secondary Basins Opportunity Nobody Is Talking About

Many mineral buyers are fixated on the Permian. That’s understandable; the Permian has the deepest inventory, the most drilling activity, and the best long-term upside. But that concentration of attention has created a price problem. The Permian is firmly a seller’s market.

Market data from Enverus Intelligence® Research indicates non-Permian mineral deals are trading at around 5x cash flow, representing a market driven by production-weighted positions with limited remaining inventory. That is about half the average multiple in the comparatively inventory-rich Permian. The Eagle Ford, Haynesville, and secondary Permian offerings can offer more value if buyers focus on finding off-market mineral opportunities that don’t show up in standard channels.

The buyers winning in secondary basins right now are the ones who have visibility into what’s actually trading there. They see the deals, they move fast, they close while other buyers don’t know there is an opportunity.

How Access Changes Everything

Most mineral buyers rely on a combination of traditional sourcing channels. Brokers, direct mailers, and personal relationships. Each channel has real costs and real constraints.

  • Brokers work a curated network. They know a subset of sellers and a subset of inventory. When deal flow is tight, you’re competing against every other buyer working with that same broker. Negotiation happens after multiple other offers have already come in, and you’re negotiating brokered terms and commissions.

  • Direct mailers reach potential sellers, but the approach is expensive and response rates are low. You’re spending time and capital hoping someone in your mailing list wants to sell. You don’t have visibility into what’s trading in your target basins or what prices are driving those transactions. You’re not seeing the market. You’re hoping the market comes to you.

  • Personal relationships and network building matter, but they’re time intensive and geographically limited. Relationships don’t scale across states and counties.

What’s missing from all three approaches is one essential thing. Visibility into the actual market. Comprehensive market visibility into hidden mineral inventory, changes everything operationally. You can search the market directly instead of waiting for a broker to send a deal or hoping a mailer responds. You see individual owner interests. You see off-market mineral rights. You see properties that fit your criteria before anyone else has approached the seller. Instead of competing against multiple other offers after a broker package goes wide, you’re having a first conversation with an uncontacted seller. Instead of negotiating around brokered terms and commissions, you’re structuring a deal that works for them.

The speed advantage is significant. A brokered deal typically takes months from first approach to close. A mailer campaign takes weeks just to see if there’s response. Direct access to market visibility compresses this to weeks from discovery to offer. You find a property that fits, you reach out, you understand the seller’s motivations, and you present an offer they can say yes to. The time-to-decision drops dramatically, and you’re the only voice in the conversation.

Every buyer can read production data. Most can do the math. But the buyers closing deals at better terms are the ones who know about them first and can structure an offer before competition arrives.

If the Consolidation Trend Continues

The near-term market appears likely to maintain current trends. EIR’s view is that consolidators will keep consolidating, and prices in the Permian will likely keep climbing. Broker deal flow will continue to shrink. But what’s changing is where real opportunity lives. It’s not in competing for brokered packages in the Permian. It’s in having direct access to the fragmented inventory that the big consolidators aren’t targeting because it doesn’t move the needle for them at scale. The interests buyers are currently holding. The owners willing to sell. That’s where the next decade of mineral acquisitions can happen.

The buyers winning right now have visibility into that inventory. Everyone else is waiting for a deal to appear on their desk and then competing with three other offers.

Take a look at what’s available on Minerals Marketplace map. See active listings across major basins, production data, and available interests that never make it to traditional deal flow. That’s your advantage.

Mineral Marketplace Map
Visit Minerals Marketplace

About Enverus Intelligence® | Research, Inc. (EIR)

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 macroeconomic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.

Enverus Intelligence® Research Press Release - Waha prices expected to go negative (again)

Bring Your Own Power | Google Funds 890 MW of Nuclear Uprates in PJM

Uncontracted Nuclear Capacity

GOOGL contracted for 3,590 MW of power from CEG in PJM, the largest U.S. power market, with new nuclear capacity accounting for about a quarter of the total, the companies said Oct. 6. A 20-year power purchase agreement covers 890 MW of incremental capacity from uprates at 11 CEG-owned nuclear units in Illinois, Pennsylvania and New Jersey. The agreement will support more than $4.3 billion of investment, with the first uprated plant expected online in 2028. Under a separate 15-year agreement, CEG will supply 2,700 MW from its PJM fleet. The power is not tied to a specific source, and GOOGL said the agreement provides long-term revenue certainty for CEG’s operating plants. The arrangement responds to PJM’s “bring your own power” proposal, which would expose large new loads without sufficient supporting capacity to curtailment during grid emergencies.

Nuclear uprates have emerged as the fastest route to firm capacity, and deals are stacking up. AMZN and CEG agreed Sept. 30 to a 20-year, 690 MW contract at the Calvert Cliffs Clean Energy Center in Maryland. The deal supports more than $3 billion of investment, including an uprate expected to add about 190 MW between 2030 and 2032. Days later, the U.S. Department of Energy announced a conditional loan commitment of up to $4.2 billion for uprates and modernization at VST’s Beaver Valley, Davis-Besse and Perry plants. The projects would add 433 MW and preserve nearly 4 GW of baseload capacity in PJM. Hyperscaler offtake and federal financing are supporting more output and longer operating lives at existing reactors without requiring new plants.

CEG was the obvious counterparty. Enverus Intelligence® Research previously measured uncontracted nuclear capacity across independent power producers and sorted it into five tiers. CEG held more than 20 GW, about seven times VST’s roughly 3 GW, including nearly 8 GW in Tier 1 (Figure 1). Calvert Cliffs ranked first, and AMZN contracted with the plant about two months later.

The deal lands in a market short on capacity and long on load. Rising electricity demand, driven largely by data center expansion, has contributed to a more than 11-fold increase in PJM capacity prices since 2024 and left the grid with a power shortfall. CEG previously agreed to restart the Crane Clean Energy Center, formerly Three Mile Island Unit 1, for MSFT data centers, while GOOGL contracted to restart NEE’s Iowa nuclear plant. CEG shares closed Oct. 6 at $300.40, up 12.25%. The companies also established a framework that could be replicated for generation, battery storage and demand-response resources elsewhere in the U.S.

This blog offers just a glimpse of the powerful analysis Power and Energy Transition Research delivers on the trending themes. Don’t miss the full picture.

Get the Full Picture

DID YOU KNOW?

A nuclear fuel pellet is about the size of a pencil eraser, yet it holds the energy of a ton of coal or 17,000 cubic feet of natural gas. Stacked inside a fuel rod, ten pellets power a home for a full year.

Research Highlights

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    Shell Energy North America’s acquisition of the 169 MW Hunlock Power Station underscores the value of strategically located gas-fired generation that combines capacity revenue with potential upside from evolving power market fundamentals.
  • 3Q26 Data Center Capacity Forecast | The Buildout Surge
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Upcoming Events

  • Roadshow | Supply Chain, Power | Oct. 13 | San Francisco, Los Angeles

Top Three Takeaways:

1: What does the GOOGL and CEG deal include for nuclear uprates in PJM?

GOOGL contracted for 3,590 MW of power from CEG in PJM, with new nuclear capacity accounting for about a quarter of the total. A 20-year power purchase agreement covers 890 MW of incremental capacity from uprates at 11 CEG-owned nuclear units in Illinois, Pennsylvania and New Jersey. The agreement will support more than $4.3 billion of investment, with the first uprated plant expected online in 2028. A separate 15-year agreement covers 2,700 MW from CEG’s PJM fleet.

2: Why are nuclear uprates becoming the fastest route to firm capacity?

Hyperscaler offtake and federal financing are supporting more output and longer operating lives at existing reactors without requiring new plants. AMZN and CEG agreed Sept. 30 to a 20-year, 690 MW contract at the Calvert Cliffs Clean Energy Center in Maryland. The U.S. Department of Energy also announced a conditional loan commitment of up to $4.2 billion for uprates and modernization at VST’s Beaver Valley, Davis-Besse and Perry plants further out.

3: Why was CEG the obvious counterparty for hyperscaler nuclear deals in PJM?

Enverus Intelligence® Research measured uncontracted nuclear capacity across independent power producers and sorted it into five tiers. CEG held more than 20 GW, about seven times VST’s roughly 3 GW, including nearly 8 GW in Tier 1. Calvert Cliffs ranked first, and AMZN contracted with the plant about two months later.

About Enverus Intelligence® | Research, Inc. (EIR)

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 macroeconomic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.

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Haynesville at the Crossroads: Weighing Gulf Coast Access Against Inventory Quality

Choosing where to drill for gas comes down to two things: how good the inventory is and how easily the gas reaches buyers. On one hand, the Haynesville trails other gas plays on inventory quality. On the other, it sits close to the Gulf Coast, where much of the new LNG demand is landing.

According to Enverus Intelligence® Research estimates, with gas below $3, the Haynesville has roughly 12 years of inventory that breaks even under that price. The Western Haynesville is an emerging area, with early wells producing more gas in year one than legacy wells.

Five or six operators account for over 50% of production, but a long tail of smaller operators has been increasing activity anyway. If you run a smaller operation, you’re weighing whether Gulf access justifies drilling here.

Lauren Van Der Wissel (Enverus Intelligence® | Research) and Kadira Singh (Technical Advisor) walked through that tradeoff in our Basin Insights webinar. Here are the four takeaways you should know:

  • Weaker inventory, but closer to LNG demand
  • Smaller operators ramped up rigs below $3
  • Western Haynesville wells started strong, but recent results are weaker
  • Ranking remaining inventory by breakeven and NPV beats blanket acreage assumptions

Proximity to LNG Demand Offsets Weaker Inventory

Lauren’s opening chart plots years of remaining inventory across the major gas plays, colored by PV10 breakeven.* Most of the Haynesville’s remaining inventory sits in the south, where it overlaps the Middle Bossier. The Marcellus and Utica rank ahead of the Haynesville on inventory quality, but those producers have historically been egress constrained and struggle to move gas to the Gulf Coast, where LNG demand is high. The Haynesville sits beside that demand, which gives it a unique advantage over other higher-quality plays. *(Breakevens are PV10 half-cycle.)

Smaller Operators Keep Adding Rigs Below $3

Despite gas below $3 and weaker inventory than the Marcellus and Utica, smaller operators have been increasing activity. One operator, Apex, has ramped to as many as 14 rigs since Q1 2025, mostly in Texas, and is now down to 10. Lauren pointed to LNG contracts, potential economic improvements, and investment decisions made when prices were higher as reasons rigs across the Haynesville have climbed. The question is whether their inventory can sustain that pace.

Apex Dropped 4 Rigs
Source | Enverus Intelligence® Research, Enverus FOUNDATIONS®, Enverus Activity Analytics.

Western Haynesville: Strong Early Results, Weaker Recent Results

Western Haynesville wells drilled in 2022 produced more gas in year one than legacy Haynesville wells, but results vary by county and depth. Recent results are weaker, with early Robertson County wells outperforming more recent Leon County wells. Operators also choke wells differently, with Comstock showing sharper declines and Aethon, now Mitsubishi’s Adamas, a flatter profile. Higher-horsepower rigs and longer laterals, nearing two miles, have pushed drilling efficiency up year over year from 2022 to 2025, to about 600 feet per day.

Western Haynesville Up to 6 Rigs
Source | Enverus Intelligence® Research, Enverus FOUNDATIONS®, Enverus Activity Analytics

Rank Remaining Inventory by Breakeven and NPV

In PRISM, rigs, forecasts, economics, geoscience, and inventory sit in one workflow, so analysts skip the hand-offs to PowerPoint and ArcGIS. Kadira showed how Placed Wells Intelligence gives you an analyst-placed, well-level view of remaining inventory, built on each operator’s historical spacing. You rank wells by breakeven and NPV instead of relying on blanket acreage assumptions. Enverus ONE, a separate subscription, takes those placed wells through a 13-step Inventory Evaluation workflow to cash flow, NPV, and IRR, with 20+ inputs you can adjust and rerun.

See the Full Picture

The inventory chart behind this tension and the live product demo are in the full replay.

Watch the full Haynesville webinar replay

About Enverus Intelligence® | Research, Inc. (EIR)

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 macroeconomic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.

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Jupiter in Retrograde | Oracle Hedges on Bloom’s Biggest Order

BE Product and Service Backlog | Source: Enverus Intelligence® Research

Last week, Oracle issued a force majeure notice to STACK Infrastructure, the Blue Owl Capital-owned developer of Project Jupiter, the Stargate data center campus in Doña Ana County, New Mexico. The notice preserves Oracle’s ability to seek delayed payments if the campus misses its targeted 2028 opening, although it is unclear whether the company could be released from its agreed obligations. Oracle says Project Jupiter “remains on our planned schedule” and that such notices do not by themselves indicate a delay. Still, Enverus Intelligence® Research (EIR) views the notice as a clear sign that Oracle sees material schedule risk.

That risk is not new. The project still lacks an air permit for its fuel-cell microgrid, and New Mexico twice blocked Energy Transfer’s Green Chile gas pipeline from crossing state trust land, pushing its targeted in-service date from August to February 2027. The New Mexico Supreme Court temporarily paused the air- and water-permitting proceedings before lifting the stays on Sept. 17. Lenders have also taken note, with the project’s $18 billion in loans quoted at 89 to 91 cents on the dollar.

Oracle’s contract with Bloom Energy (BE) covers about 2.4 GW of fuel cells for the site and, including a $1.2 billion expansion option, represents nearly half of BE’s estimated product backlog. EIR still expects Project Jupiter to be built. Oracle is not walking away; the project partners say their financial commitments remain unchanged, and the compute demand underpinning Stargate is real.

But the notice is Oracle’s own acknowledgment that the 2028 target faces risk, and every month of delay could push BE’s deliveries and revenue further out. In July, we called the pipeline denial Bloom’s first crack. This is the second, and with so much of its estimated backlog tied to one site, BE has little room for error.

This blog offers just a glimpse of the powerful analysis Power and Energy Transition Research delivers on the trending themes. Don’t miss the full picture.

Get the Full Picture

Research Highlights:

  • Network Upgrade Costs and Solar PV – LCOE Zonal Exposure and Sensitivity – Enverus Intelligence® Research identifies the independent system operator zones with the lowest solar PV network upgrade costs (NUCs). It also examines how NUC outcomes affect the levelized cost of energy and compares solar economics without the investment tax credit with recent power purchase agreement benchmarks.
  • 3Q26 Long-Term Capacity Expansion – The Reliability-Led Power Buildout – Enverus Intelligence® Research projects a storage-led buildout of the Lower 48 power supply through 2050, with 1,080 GW of new capacity lifting installed capacity from 1,435 GW to 2,284 GW. Battery storage, solar and natural gas lead additions, but the path diverges sharply by region as some markets scale renewables while others lean on gas and nuclear. Falling geothermal and nuclear costs and rising gas capex reshape where each technology wins.
  • ERCOT Batch Zero – Who Gets Energized, Who Waits? – ERCOT’s Batch Zero classification gives large-load developers a sense of their path to energization, but certainty remains limited. We find that only 8.8 GW of the 191.8 GW classified is associated with published near-term Quarterly Stability Assessment deadlines, while the largest and least visible projects face additional study and transmission uncertainty.

DID YOU KNOW?

Force majeure is French for “superior force,” and the concept was written into France’s Civil Code in 1804. It pauses obligations when events outside a party’s control, traditionally wars, floods and “acts of God,” make performance impossible.

Top Three Takeaways:

1: What does Oracle’s force majeure notice mean for Project Jupiter?

Oracle’s force majeure notice is a legal safeguard that allows the company to delay payments if Project Jupiter misses its 2028 opening target. While Oracle maintains the project is on schedule, EIR views the notice as a clear signal the company sees material schedule risk ahead. The notice does not necessarily indicate an imminent delay, but it reflects Oracle’s concern about permitting and infrastructure challenges that could push the timeline.

2: How dependent is Bloom Energy on Project Jupiter?

Bloom Energy’s 2.4 GW fuel cell contract for Project Jupiter represents nearly half of the company’s estimated product backlog, making it a critical revenue stream. The contract includes a $1.2 billion expansion option, further cementing the site’s importance to the company’s future deliveries and financial performance. With so much of its backlog concentrated at a single location, Bloom Energy has limited flexibility if schedule delays push fuel cell deliveries
further out.

3: What are the primary schedule risks facing Project Jupiter?

The project faces multiple permitting and infrastructure hurdles: it still lacks an air permit for its fuel-cell microgrid, and New Mexico’s twice-blocked Energy Transfer pipeline has pushed its in-service target from August to February 2027. Lender concerns are mounting, with project loans quoted at 89 to 91 cents on the dollar, signaling diminished confidence in timely completion. Every month of delay ripples through Oracle’s procurement and Bloom Energy’s delivery timeline.

About Enverus Intelligence® | Research, Inc. (EIR)

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 macroeconomic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.

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LNG Canada Phase 2, Pipeline Optionality and Oil Market Confusion

Canada’s energy future hinges on market access and optionality.

LNG Canada Phase 2 has secured a final investment decision, while provincial premiers align on oil pipeline ambitions, underscoring Canada’s push to become a global energy superpower. In this segment from CBC Calgary’s Eyeopener, Al Salazar breaks down the LNG decision, the political momentum behind east- and west-coast pipelines, and why stock levels, not headlines, will ultimately drive prices.

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LNG Canada Phase 2: Validation of an Energy Superpower Ambition

LNG Canada Phase 2 securing a final investment decision signals market fundamentals are aligned with supply expansion. With roughly 10 Bcf/d of LNG supply disrupted by the U.S.-Iran war, some price-sensitive Asian buyers have pivoted to coal or reduced consumption. These near-term conditions have strengthened the case for Phase 2, despite its longer development timeline. Middle East instability also casts a dark cloud over low-cost Qatari LNG, while Canada offers greater security of supply.

LNG Canada vs. Qatari LNG: Why Supply Security Drives Investment

The geopolitical backdrop makes LNG Canada increasingly attractive to Asian buyers seeking diversified sources. With Middle East tensions threatening supply chains and Qatari volumes constrained, LNG Canada’s appeal extends beyond just price—it’s about de-risking supply portfolios. The Final Investment Decision validates that LNG Canada can compete on both economics and security, positioning the project as critical to Canada’s energy superpower aspirations.

Hormuz traffic is improving, but that matters little if shut-in production does not return and Russian refineries remain offline. Global crude and product inventories are still declining. Shipping delays may eventually slow inventory draws, but the market still faces a long recovery. Less attention is being paid to how traffic is being restored: through an increasingly demanding and potentially unsustainable U.S. military commitment.

The Premiers’ Alignment on Canadian Pipeline Expansion: Why Infrastructure Becomes Political Capital

Ontario Premier Doug Ford’s support for the Northern Shield Energy Corridor, including provincial funding for feasibility work, signals a shift in how political leaders view energy infrastructure. The stated four- to five-year construction timeline acknowledges urgency; the willingness to deploy public funds addresses investor anxiety about regulatory delays. We interpret this as recognition that Canada’s energy superpower ambitions require new infrastructure and the market optionality it provides.

Price Differentials and the Venezuelan Squeeze: Why Shipping Constraints Matter More Than Sentiment

Western Canadian Select has recently traded at an increasingly wide discount to Brent. Venezuelan barrels have begun to compete for U.S. Gulf Coast refining capacity, while U.S. refinery outages have reduced demand for Canadian crude. Further Venezuelan production gains could crowd Canadian barrels out of finite Gulf Coast refining capacity. We warned about this dynamic months ago. For a deeper analysis of how Venezuelan competition reshapes Canadian energy economics, see Trump’s Venezuela Deal Puts Canada “On Notice”: What It Means for Oil Sands and Pipeline Economics.

Without diversified export routes, Canadian producers could face a wider structural discount due to Venezuelan production gains. Each additional pipeline route connecting Canadian barrels with markets outside the U.S. Gulf broadens the buyer pool and provides relief through greater optionality. As detailed in Alberta’s West Coast Pipeline Gambit: Economics, Routes and the China Wild Card Shaping Canada’s Oil, exploring new Canadian pipeline corridors could fundamentally reshape pricing dynamics for upstream producers.

The Stock and Flow Illusion: Why Market Noise Masks the Real Price Support

Markets remain focused on headlines: vessel traffic through the Strait of Hormuz, Russian refinery outages and global product shortages. That has left clients struggling to separate bullish arguments from bearish ones.

Key Takeaways

Why does Canada need pipeline optionality?

Canadian crude currently trades at a significant discount to global benchmarks because of U.S. refinery outages and increased competition from Venezuela. With Venezuelan barrels competing for Gulf Coast refining capacity, wider price differentials are inevitable without diversified export routes. As explored in Why Alberta’s Oil Sands Producers Are Waiting on $100 Crude and Ottawa’s Fine Print, pipelines to the east and west coasts would give Alberta producers greater optionality and pricing power.

What would a U.S. diesel export ban mean for Canadian industries?

Quebec and Atlantic Canada import a small amount of diesel from the United States. If the U.S. restricts diesel exports, international prices would spike and private refineries would chase higher margins overseas rather than serve domestic markets. Canada would face upward pressure on diesel costs across transportation, agriculture and industrial sectors.

Why are stock levels more important than geopolitical noise?

Global crude and product inventories have fallen sharply and continue to draw. While financial markets focus on Strait of Hormuz traffic and trade headlines, physical markets reveal the central constraint: product supply. Low stock levels provide structural support for elevated oil prices, making them more durable than sentiment alone would suggest.

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.

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How Much Grid Capacity Can Your Data Center Site Actually Count On?

Knowing the grid could serve part of your load isn’t the same as knowing how much, by when, or at what cost.

A data center site can pass every land, permitting and community screen and still stall on one number: how much grid capacity it can actually count on. The first post in this series looked at why a powered site still needs to prove it’s buildable, permittable and connectable before it’s ready for capital. This post picks up at connectable.

Outside ERCOT, many large loads don’t sit in a public interconnection queue, so a developer can move deep into site planning without knowing who else is chasing the same local headroom. A nearby substation on a map doesn’t answer the real question: how much firm load can that point of interconnection actually support, by the date the project needs it?

Proximity to transmission is not the same as usable grid capacity.

Testing the number, not assuming it

A meaningful capacity assessment starts with the project’s actual load profile: target size, energization date, ramp schedule, and how much of that load has to be firm versus how much tolerance there is for bridge power. In Enverus Interconnect for Large Load, that profile is the starting screen: the same inputs a development team would already have on hand for any candidate site.

Setting up a candidate load in Enverus Interconnect for Large Load. Target capacity, energization date and ramp schedule become the inputs every downstream scenario is built from.

A single base case understates the risk. It doesn’t account for other large loads that may be competing for the same grid capacity, or for stressed system conditions that trigger a different set of network upgrades. That’s why the workflow tests more than one operating condition side by side: a traditional case built on today’s known queue, and a stressed case that assumes more of that queue actually gets built.

The same candidate load modeled under a traditional case and a stressed case.
  1. Traditional case: 3 network upgrades triggered, 209 MW of headroom, and roughly $73 million in upgrade cost.
  2. Stressed case: 5 network upgrades triggered, 1 MW of headroom, and roughly $128 million in upgrade cost.

Same load. Same node. Same target date. The only thing that changed was which projects ahead of it in line were assumed to actually get built. That’s the gap a single-case estimate hides, and it’s the difference between a site with room to grow and one with almost none.

Turning grid headroom into a decision

Once the range is established, the logic becomes concrete. How much firm load can the grid support? How big is the gap to the project’s full requested load? What upgrades would close that gap, and roughly when could they be in service?

An itemized view of the network upgrades triggered at the point of interconnection, each with its own cost and expected in-service timing.

That gap is the behind-the-meter generation requirement. It has to be sized for the shortfall, whether that’s an interim bridge while upgrades are pending or a longer-term part of the power strategy. There’s also a real decision to make about what that generation does once the bridge period ends: stay isolated, keep supporting the campus, or eventually pursue its own interconnection.

The cost spread matters as much as the headroom spread. Moving from the traditional case to the stressed case didn’t just shrink the available capacity, it added tens of millions of dollars in potential network upgrade cost. That range belongs in the site’s economics from day one, not as a footnote discovered later.

BYOG changes the grid relationship, it doesn’t end it

None of this makes the grid optional. BYOG can reduce how much a project depends on immediate full grid service, but it rarely removes the interconnection question altogether. Grid timing still affects the power ramp. Network upgrade costs still move the project’s economics. And on-site generation may eventually need its own generation-side interconnection analysis once it’s large enough to export or support neighboring load.

For most BYOG configurations, the grid doesn’t disappear from the analysis. It just becomes a smaller, later part of it.

Before advancing the site

A defensible capacity number comes down to four questions:

  • How much firm load can this location support, and what’s the credible range under stressed conditions?
  • Which upgrades are triggered at the target load size, and when does each increment of power actually become available?
  • How much bridge or permanent on-site generation does that gap require?
  • Does the grid timeline still line up with the campus development plan?

A site can clear its land, permitting and grid questions and still have one more piece to confirm: whether enough gas can actually reach it, both physically and commercially. That’s where this series goes next.

Next in the series: BYOG: Can the Gas Actually Reach Your Data Center Site?

Watch From Decision to Execution: How to Validate BYOG Sites Before You Commit to see how developers can test land, permitting, grid and fuel risks before committing capital.

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Why Lean Operators are Rethinking Their Tech Stack

In a recent post, we introduced the Lean Operator: the small team running complex programs without the staff or systems a major would bring to the same work. This post picks up where that one left off.

You’ve got a land system your predecessor built in 2019, an engineering platform you use for a fraction of your workflows, and a folder of raster files that may or may not be depth-registered. You’re running a 40-well program and answering to a sponsor who wants a development plan by Friday, and somewhere in the middle of all that, you’re expected to keep the data clean.

For a lot of Lean Operators, that’s a normal week. The root of the problem usually has less to do with how hard the team is working and more to do with how the tools underneath them fit together.

The Gap Caused by Enterprise-Designed Tool

Each tool in your stack probably does its job well enough on its own. The trouble starts with the handoffs. Moving from your land system to your engineering platform means rebuilding context every time, and answering a single question often means pulling from three sources that were never designed to talk to each other. That can easily eat thirty minutes you didn’t have. If you have an analyst, a good share of their week likely goes to wrangling exports instead of running analysis. If you don’t, that time has to come from somewhere in yours.

Over the course of a week, those handoffs can add up to something close to a full workday. You won’t find that on a budget line, but you’ll see it in slower decisions, evaluations that took longer to finish than they should have, and opportunities that moved on before you were ready.

Meanwhile, the ask keeps growing: more wells and tighter timelines, with no additional resources to help. Development plans still have to hold up in technical review, and basin screens increasingly cover acreage you’ve never operated, all on a schedule more suited to enterprise teams.

Most large-scale platforms were designed with different customers in mind, typically a 500-person organization with dedicated data teams, a full IT department, and the budget for a six-month onboarding. For a team your size, the configuration overhead alone can turn into a full-time job.

The Workflows That Expose Your Stack

Rethinking your stack doesn’t have to mean replacing all of it. Most of the Lean Operators we talk to would rather keep what works and add tools that step in at the specific points where their current setup falls short. Three workflows come up repeatedly in our calls.

1: Quick Evaluation

A seller calls, or you’re screening an acquisition target at 4 p.m. on a Thursday, and you need production data, basic engineering context, and ownership information in one place before the conversation moves on. A full analysis platform is more than the situation calls for. What you need is a reliable answer, fast.

Strike was built for that workflow. It gets you from question to answer in about three clicks, with no lengthy setup or training standing between your team and the first useful result.

2: De-Risking the Subsurface

Maybe you picked up acreage in a divestiture, or you’re screening a basin your team hasn’t worked in before. Before your geologists can trust an interpretation, they need every well log in that area of interest, not just the ones already on file. One missing offset well leaves a gap in the picture right when the stakes are highest: building a development plan, making a spacing decision, or running A&D due diligence.

Well Log Analytics Rasters gives you access to 8.1 million SmartRaster well-log images across North America, already depth-registered and UWI-assigned, so your team works from complete coverage instead of a partial one.

3: Document Search

Acquired assets tend to arrive with years of lease files, completion reports, and scanned well files, and operators send over 40-page drilling reports with no summary attached. The answer you need is usually somewhere in that folder, but finding it means reading page by page while the clock runs.

Enverus ONE QuickStart turns those files into a workspace your team can question in plain language. You can upload PDFs, PowerPoints, and images, including older typewritten reports, and every answer cites the document it came from. It’s ready in minutes, with no IT setup or data preparation required.

What’s Changing

The Lean Operators moving fastest right now favor lightweight tools their teams can start using on day one, the kind that slot into existing workflows and pay for themselves in hours saved. They get there by asking what fits the way their team works before comparing feature lists, which tends to rule out the platforms built for teams ten times their size.

If This Sounds Familiar

Strike was designed around how Lean Operators work. If quick evaluations are where your current setup tends to break down, it’s worth a look.

See Strike In Action

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Solar Save | Court Halts EPA Program Repeal

Residential Solar Additions by Load Zone | Source: EIR

Last week, a federal judge ruled the EPA unlawfully terminated its Solar for All program, which was designed to expand solar access in lower-income communities. The judge found the agency’s action violated the Administrative Procedure Act, rejecting the EPA’s claim that the One Big Beautiful Bill Act authorized it to cancel the $7 billion program. The EPA had estimated that the program would reach more than 900,000 lower-income households.

Solar for All was part of the $27 billion Greenhouse Gas Reduction Fund created under the 2022 Inflation Reduction Act (IRA). The remaining $20 billion, allocated to other grant programs, is subject to separate litigation and was not directly affected by this ruling. The EPA is reviewing the decision and considering an appeal.

The ruling marks a legal setback for the EPA as it continues to roll back emissions standards elsewhere, including its recent partial repeal of carbon pollution standards for fossil fuel-fired power plants. Annual rooftop solar installations, currently around 7 GW, are forecast to reach 8 GW by 2030, with growth depending partly on incentives such as Solar for All. Vacating the program’s termination removes one legal obstacle to that growth and suggests some IRA incentives may prove more durable than the Trump administration expected.

This blog offers just a glimpse of the powerful analysis Power and Energy Transition Research delivers on the trending themes. Don’t miss the full picture.

Get the Full Picture

Research Highlights:

  • 3Q26 Long-Term Capacity Expansion – The Reliability-Led Power Buildout – Enverus Intelligence® Research projects a storage-led buildout of the Lower 48 power supply through 2050, with 1,080 GW of new capacity lifting installed capacity from 1,435 GW to 2,284 GW. Battery storage, solar and natural gas lead additions, but the path diverges sharply by region as some markets scale renewables while others lean on gas and nuclear. Falling geothermal and nuclear costs and rising gas capex reshape where each technology wins.
  • ERCOT Batch Zero – Who Gets Energized, Who Waits? – ERCOT’s Batch Zero classification gives large-load developers a sense of their path to energization, but certainty remains limited. We find that only 8.8 GW of the 191.8 GW classified is associated with published near-term Quarterly Stability Assessment deadlines, while the largest and least visible projects face additional study and transmission uncertainty.
  • Grid Supply Chain Risk – Few Suppliers, Many Developers Exposed – EIR provides a data-driven analysis of the grid equipment, manufacturers and developers most exposed to Executive Order 14421 restrictions on foreign-produced bulk-power-system equipment.

DID YOU KNOW?

Solar panels generally lose power as their cells heat up. Crystalline silicon has a negative power-temperature coefficient, so a hot panel can produce less instantaneous power than an otherwise identical, cooler panel, even if the cooler panel is receiving slightly less sunlight. This is one reason extremely hot desert sites do not always deliver the highest instantaneous efficiency. Nevertheless, deserts often produce more energy over a year because their stronger solar resource and clearer skies usually outweigh heat-related losses.

Top Three Takeaways:

1: Why did a federal judge block the EPA’s repeal of the Solar for
All program?

A federal judge ruled that the EPA unlawfully terminated Solar for All, finding the agency’s action violated the Administrative Procedure Act. The judge rejected the EPA’s argument that the One Big Beautiful Bill Act authorized it to cancel the $7 billion program, which the EPA had estimated would reach more than 900,000 lower-income households.

2: What is the Solar for All program and how does it connect to the Greenhouse Gas Reduction Fund?

Solar for All was part of the $27 billion Greenhouse Gas Reduction Fund created under the 2022 Inflation Reduction Act. It was designed to expand solar access in lower-income communities, with $7 billion allocated specifically to this program while the remaining $20 billion supports other grant programs currently facing separate litigation.

3: What does this ruling mean for rooftop solar growth through 2030?

Annual rooftop solar installations, currently around 7 GW, are forecast to reach 8 GW by 2030, with growth depending partly on incentives such as Solar for All. Vacating the program’s termination removes one legal obstacle to that growth and suggests some IRA incentives may prove more durable than the Trump administration expected.

About Enverus Intelligence® | Research, Inc. (EIR)

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 macroeconomic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.

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You Can’t Print Barrels

Global oil markets tightened dramatically this week after Iranian strikes on Saudi Arabia’s East-West pipeline and a Houthi seizure of a strategic Red Sea chokepoint pushed Brent and WTI above $100 a barrel. Understanding the Brent and WTI price surge causes means looking past the screen price to what’s happening in physical markets. Click here to listen to the full interview.

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A 10-to-12-Million-Barrel Hole in Global Oil Supply

Before last weekend’s events, the International Energy Agency (IEA) estimated roughly 8 million barrels a day of global oil supply offline. The Houthi seizure of a chokepoint island at the southern entrance of the Red Sea and the outage on Saudi Arabia’s East-West pipeline pushed that figure to something closer to 10 to 12 million barrels a day. These Houthi attacks on maritime trade have added a second front to the crisis, layering shipping risk on top of the pipeline outage. The starkest number in that total is Saudi Arabia’s export capacity: the kingdom, OPEC’s swing producer, can currently move only about 1 million barrels a day to market, down from a typical level of roughly 6 million.

Inventories are not providing much cushion either. Draws on the U.S. Strategic Petroleum Reserve are becoming harder to sustain. The salt caverns that store the oil require water injection to force barrels out, a process that damages the reservoir the more it is used. With demand showing no signs of slowing, the buffer that normally absorbs a shock to global oil supply is increasingly thin.

Why the Physical Barrel Already Trades at $130

Headline prices near $107 Brent understate what is happening in physical markets. The physical barrel is trading closer to $130. Converted into refined products, that works out to roughly $170 a barrel for gasoline and over $200 a barrel for diesel at the pump. Strikes on Russian refining capacity are compounding the product-side squeeze, which we cover in more detail in Diesel’s Hundred-Dollar Crack. Our analysis highlights refining outages, not crude supply, as the bigger driver of pain at the pump.

The disconnect matters because $107 on the screen is a level the market has seen before and largely shrugged off. The physical barrel at $130, and the product barrel well above that, is not. We think this gap shows the crisis is already here even though the futures screen has not fully caught up with the reality of tightening global oil supply.

Demand Hasn’t Cracked, Yet

Canadian and U.S. gasoline and distillate demand are flat year on year, with no contraction so far. The demand response has instead shown up in Asia and emerging markets, which we estimate are on pace to contract by around 2 million barrels a day this year. In North America, consumers are absorbing higher prices by cutting other parts of their household budget rather than driving less.

Our view is that a real break in Western demand only happens if the broader economy slows and job losses follow. Short of that, prices likely need to keep rising to force the market back into balance because neither storage nor backup supply is available to do that work instead.

Three Paths to De-escalation, None Easy

We see three broad ways this resolves and none look clean. Direct U.S. military action risks further retaliation against energy infrastructure, which is already being targeted by multiple actors. Economic sanctions, the path currently favored, have a weak track record of quickly restoring lost barrels. A Gulf Cooperation Council-brokered de-escalation looks unlikely so soon after Iran struck Saudi infrastructure directly. For more on how this standoff has been building, see our earlier note, Brent Near $100 While the Market Sleeps on Supply Risk, and our broader thesis in $100 Realities: Why the Middle East Now Sets the Floor for Oil Prices.

Absent one of those three paths working, the market is left doing what it has increasingly had to do this year: finding ways to use less OPEC oil rather than waiting for more of it.

Alberta’s Investment Moment, and the Carbon Capture Question

Away from the geopolitics, the Canada Investment Summit wrapped this week with Alberta carrying, by one analyst’s account, the biggest book of business on the table. Alberta oil sands investment opportunities were a central theme, with Former Prime Ministers Stephen Harper and Jean Chrétien both in attendance, as were BlackRock’s Larry Fink and Blackstone’s Jon Gray. The message from Ottawa was that regulatory processing on energy applications will move faster. Carbon capture was pitched as one of Alberta’s strongest opportunities, built on the province’s geological advantage for underground storage, though monetizing it still comes down to whether carbon credit pricing is certain enough to make the economics work. Why Alberta’s Oil Sands Producers Are Waiting on $100 Crude and Ottawa’s Fine Print.

Prime Minister Mark Carney’s reference to a “carbon-friendly crude oil export pipeline” ties this directly to any West Coast pipeline ambitions, since capturing and holding onto emissions is the mechanism that would make such a project politically viable. We laid out the route and economics of that option in Alberta’s West Coast Pipeline Gambit, and it remains the key swing factor to watch as these talks move from summit rhetoric to capital commitments.

Key Takeaways

Why hasn’t $107 oil triggered a bigger demand response?

  • Because U.S. and Canadian gasoline and distillate demand are holding flat. Consumers are absorbing higher pump prices by cutting other parts of their budget rather than driving less. The roughly 2 million barrels a day contraction we are seeing this year is concentrated in Asia and emerging markets, not the West. A real break in North American demand would likely require a broader economic slowdown and job losses.

What is the significance of Saudi Arabia’s export capacity falling to about 1 million barrels a day?

  • Saudi Arabia is OPEC’s swing producer and typically exports 5 to 6 million barrels a day. A drop to roughly 1 million, following the East-West pipeline outage, strips out the market’s most reliable spare capacity cushion at the same time the Houthi chokepoint seizure adds further disruption to global oil supply. That combination is a large part of why we think prices need to keep climbing to force the market back into balance.

What factors are preventing a quick resolution to the supply crisis?

  • None of the available paths look clean. Direct U.S. military action risks further retaliation against energy infrastructure from multiple actors already targeting it. Economic sanctions have a weak history of quickly restoring lost barrels. And a Gulf Cooperation Council-brokered de-escalation looks unlikely so soon after Iran struck Saudi infrastructure directly.

About Enverus Intelligence® | Research, Inc. (EIR)

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 macroeconomic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.

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Extended Stay | EPA Clears the Runway

Retirement Delays
Coal and Gas Plant Retirements are being Extended | Source: EIR

The Environmental Protection Agency has repealed most of the Biden administration’s 2024 greenhouse gas emissions requirements for coal- and gas-fired power plants and proposed eliminating remaining standards. The revoked provisions would have required certain existing coal plants and new baseload gas plants to capture 90% of their carbon pollution or retire. EPA officials presented the rollback as a trade-off that would reduce compliance costs and support grid reliability as power demand accelerates.

The timing is notable. Over the past two years, capital costs for new combined-cycle gas turbines have roughly doubled or tripled. This has made new projects difficult to finance without long-term power price agreements or unusually high capacity revenues. As a result, utilities have opted for the cheaper alternative of meeting load growth by extending the lives of existing plants. Enverus Intelligence® Research (EIR) data shows coal- and gas-fired plants have increasingly delayed retirements, particularly in regions experiencing high load growth where grid operators cannot afford to take capacity offline.

The 2024 rule was one of the few forces working against that trend. Its partial repeal gives utilities greater latitude to preserve existing capacity, reinforcing what economics and reliability needs were already pushing them to do.

This blog offers just a glimpse of the powerful analysis Power and Energy Transition Research delivers on the trending themes. Don’t miss the full picture.

Get the Full Picture

Research Highlights:

  • Wired for Growth – The Congestion Premium – This report examines where power prices are diverging most from local gas prices across ERCOT and PJM. It identifies the markets, generation assets and power producers best positioned to benefit from elevated spark spreads driven by low-cost gas, load growth and transmission congestion. The analysis also assesses how plant utilization and hedge exposure could shape the opportunity.
  • BP’s Archaea RNG Portfolio – Pricing the Exit – We model the current value of BP’s Archaea renewable natural gas and landfill-gas-to-power portfolio, compare it with the 2022 acquisition price and estimate potential sale proceeds using recent transaction comparables.
  • Power Delivery Risk – Time From Approval to In-Service – EIR benchmarks transmission-upgrade delays using 5,901 completed records across ERCOT, MISO, PJM and SPP, paired with constraints at 47,488 interconnection points. ERCOT’s median authorization-to-energization period is longest at 32.7 months versus 23.5 in MISO, with every voltage class slower. Load size drives upgrade dependency, while operator choice matters as much as market choice, with median build times ranging from 12 to 43 months.

DID YOU KNOW?

The average coal-fired power plant in the U.S. is over 40 years old, and the ten oldest ones running today were built between 1943 and 1949, during World War II. Many of these plants keep going well past when engineers expected them to retire, kept alive by regulatory extensions, grid reliability needs, or a lack of cheaper replacement options.

Top Three Takeaways:

1: What did the EPA’s power plant rule rollback change?

The EPA repealed most of the Biden administration’s 2024 greenhouse gas emissions requirements for coal- and gas-fired power plants and proposed eliminating the remaining standards. The revoked provisions would have required certain existing coal plants and new baseload gas plants to capture 90% of their carbon pollution or retire. EPA officials framed the move as reducing compliance costs and supporting grid reliability as power demand accelerates.

2: Why are coal and gas plant retirements being extended?

Capital costs for new combined-cycle gas turbines have roughly doubled or tripled over the past two years, making new projects hard to finance without long-term power price agreements or unusually high capacity revenues. As a result, utilities are opting for the cheaper path of extending the lives of existing plants, especially in regions with high load growth where grid operators can’t afford to take capacity offline.

3: How does the EPA rollback affect utilities’ retirement decisions?

The 2024 rule had been one of the few forces pushing plants toward retirement. Its partial repeal gives utilities greater latitude to preserve existing coal and gas capacity, reinforcing a trend that economics and reliability needs were
already driving.

About Enverus Intelligence® | Research, Inc. (EIR)

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 macroeconomic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.

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