Enverus Press Release - OFS prices expected to bottom out by year’s end

Trump’s Venezuela Deal Puts Canada “On Notice”: What It Means for Oil Sands and Pipeline Economics

President Trump’s announcement of what he called the biggest oil deal in world history, granting the United States majority control over 65 billion barrels of Venezuelan oil reserves, has reopened the conversation about Canada’s leverage in North American energy trade. Trump followed with a warning that the deal puts Canada “on notice.” 

Click here to listen to the full interview.

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A Five- to Ten-Year Horizon, But Notice Served Today

None of Friday’s announcements move markets today. Chevron confirmed it is aiming to double its Venezuelan production from 300,000 to 600,000 barrels a day over roughly five years, and the broader Venezuela opening sits on a five- to ten-year horizon before it materially changes flows. But timelines matter less than positioning. We read Trump’s “on notice” comment as a negotiating tactic in the middle of an active trade war: the administration is signaling it has options for crude supply beyond Canada, even as officials like Alberta Premier Danielle Smith insist energy exports are not a bargaining chip.

Where Oil Sands Barrels Actually Compete

Oil sands producers are less exposed to this shift than the headlines suggest, but not immune to it. Most Canadian barrels move through Pad 2 into Midwest refining, a fixed relationship that isn’t changing. The exposure sits with the smaller volume of Canadian crude that reaches the Gulf Coast, where the White House has been explicit that Venezuelan barrels are intended for U.S. refineries. That is where Venezuelan supply and Canadian supply will compete directly. It’s a dynamic we’ve been tracking closely in our work on Alberta’s oil sands producers waiting on $100 crude and Ottawa’s fine print.

The MOU Pipeline’s Math Gets Harder, Not Easier

The proposed MOU pipeline, estimated at roughly $40 billion, was already an expensive way to move barrels to tidewater; the Venezuela deal adds a new layer of demand uncertainty for a project that won’t be in the ground for years. Proponents may see momentum building given growing calls for diversified export routes, but the end-use case is now less clear than it was a year ago. We explored the route economics and the China dimension of that debate in Alberta’s West Coast Pipeline Gambit, and the Venezuela announcement only sharpens the question of who the marginal barrel is ultimately competing against.

Alberta’s Budget Math Looks Overly Conservative

Alberta’s latest budget review assumes WTI averages $73.50 USD/bbl for the fiscal year, with the already-settled portion of the year at $86. The government would only need WTI to settle in the high $50s to low $60s for the remainder. The current WTI curve for that same stretch averages closer to $83, roughly $20 above the province’s assumption. Given that gap, we wonder why Alberta refuses to hedge, as they too recognize that oil prices are volatile, as discussed in Navigating Alberta’s Oil Volatility: Strategies for Economic Stability.

Line 5, Hormuz, and Why Our Price View Hasn’t Moved

Line 5 is unlikely to become a bargaining chip: Canadian crude feeds Sarnia refineries, but the gasoline and diesel produced there flow back into the U.S., so restricting the line cuts both economies at once. Separately, the Strait of Hormuz crisis just crossed its six-month mark with no resolution, and a brief Iran-Oman revenue-sharing arrangement that pressured prices lower has since stalled. We don’t see the Venezuela deal changing our near-term price view; it’s a longer-horizon supply story layered on top of a Hormuz risk premium that remains very much intact, a dynamic we detailed in Brent Near $100 While the Market Sleeps on Supply Risk. With Ottawa also extending the federal excise tax holiday on gasoline and diesel to the start of 2027, we remain bullish on both gasoline and oil into year end.

Key Takeaways

Why did Trump say the Venezuela deal puts Canada “on notice”?

  • The comment is a negotiating tactic amid an active trade war. By expanding U.S. access to Venezuelan barrels, potentially rising from 300,000 to 600,000 barrels a day of Chevron production over five years, Washington is signaling it has crude supply alternatives, which strengthens its hand in broader trade talks with Canada.

What is the significance of the Gulf Coast for Canadian oil sands producers?

  • Most oil sands crude is locked into Midwest refining via Pad 2 and isn’t affected. The Gulf Coast is the smaller slice of Canadian exports, but it is exactly where the White House says Venezuelan barrels will be refined, putting the two supplies into direct competition.

What factors are preventing the Venezuela deal from changing near-term oil prices?

  • The deal operates on a five- to ten-year timeline before it materially adds barrels to the market. In the near term, the six-month-old Strait of Hormuz crisis and a stalled Iran-Oman arrangement remain the dominant price drivers, which is why our short-term outlook hasn’t shifted.

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 - The Canadian oil sands’ low-breakeven resource advantage

The Ticket That Gets Signed Twice: Getting Field Spend Out of the Paper Age

This story is drawn from a session Devon Energy led at the Enverus EVOLVE conference. Watch their on-demand session here.

The Short Version

A lot of field spend in upstream oil and gas still starts with a paper ticket and a manual signature, which forces approvers to sign twice, slows vendor payment, and lets invoices drift from the agreements behind them. This piece looks at how one operator digitized field ticketing and AFE approvals, capturing the financial authority signature once at the ticket level, and what that changed for cycle time, invoice coding, and field safety.

A lot of field spend in upstream oil and gas still starts with a paper ticket and a manual signature, which forces approvers to sign twice, slows vendor payment, and lets invoices drift from the agreements behind them. This piece looks at how one operator digitized field ticketing and AFE approvals, capturing the financial authority signature once at the ticket level, and what that changed for cycle time, invoice coding, and field safety.

On most active leases, a surprising amount of spend still starts with a paper ticket and a signature. A service crew finishes a job, writes up a ticket, and someone has to physically sign it. Sometimes that means a vendor flagging down an approver on a lease road to get a piece of paper stamped. Sometimes it means the approver printing the ticket, signing it, scanning it back in, and emailing it along. The cost coding gets added by hand somewhere in that chain, and the packet eventually becomes an invoice that an accounting team has to reconcile against what was actually approved in the field.

Moving field spend off paper means approvers sign once, vendors get paid faster, and coded tickets flow straight into the invoice.

This is how a lot of field ticketing still works, and it’s especially common on AFE work, where the spend is authorized against a specific project and the approvals carry real weight. The manual version quietly taxes everyone it touches. Approvers give the same signature twice, once on paper in the field and again when the invoice lands. Vendors also wait longer to get paid, and every hand-written code is one more place an invoice can drift from the agreement behind it. Across tens of thousands of tickets a month, that adds up to slower cycle times, slower cash, and the occasional safety problem when someone has to be tracked down in person to sign.

How Do Operators Get Field Ticketing Off Paper?

Devon Energy took this on with its AFE work. Crews were still signing tickets in the field by hand, adding the cost coding manually, and sending the packet on to the vendor. Devon had already moved other categories, like water hauling and disposal, onto an Enverus digital field ticketing solution, but their AFE spend was the largest remaining category still on paper. So, the team decided it was time to digitize it.

The technology aspect wasn’t the hard part though. The harder job was persuading field managers who had run this process the same way for years, and that came down to a straightforward, practical case: capture the signature once, electronically, at the point the work is approved.

You can reduce your work, because you take that manual signature, put it in the system, and that’s your financial authority signature now. You’re no longer doing it in two different spots.

— Nick Hise, Manager, Expenditure Accounting, Devon Energy

The old way asked approvers to sign twice, once to authorize the work and again when the invoice showed up. Capturing the financial authority signature at the ticket level folds those into a single step: approve it once, where the work happens, and it does not come back around downstream. There is a safety benefit too. When approvals happen electronically, vendors no longer have to track people down on remote lease roads to get a ticket signed, which can be genuinely dangerous.

What Does Rolling Out Digital Field Ticketing Take?

Digitizing the tickets was one thing, but getting hundreds of approvers and vendors onto the system on a tight timeline was another. Devon moved its business units onto AFE ticketing on a compressed schedule and made it stick with a simple idea: office hours. The team ran dedicated call-in sessions before and after go-live, where anyone could ask a question live rather than adding another email to the queue.

It’s much quicker to answer something in a live call than to have the same question come in ten times and answer those in emails. We dedicated a lot of time to pre-go-live and post-go-live office hours.

— Megan Belcher, Lead AP Accountant, Devon Energy

A useful pattern showed up in those sessions. Many vendors called in only to confirm that Devon was not using the system differently from everyone else, because they were already on it for other operators. Onboarding became less about teaching a new tool and more about confirming that Devon worked the way the vendor already did. That is a quieter advantage of a widely adopted ticketing network, and it is not something an operator can create on its own.

What it Makes Possible

Moving field spend off paper doesn’t just mean removing the physical ticket itself from the work being done, it’s more about removing or simplifying all the manual touches that paper tickets create down the line. With AFE work captured electronically at the ticket level, approvers stop signing twice, vendors stop chasing signatures across the lease, and the coded ticket flows straight into the invoice instead of being reassembled after the fact. Some field situations will always call for a light signature or a stamp, so this is not about removing every human step. It is about removing the ones that existed only because the work lived on paper.

If your field and AFE spend still runs on manual signatures and hand-written coding, the takeaway from Devon’s experience is a practical one. The tools to digitize this work have been around for years. The harder and more valuable move is deciding to stop signing the same ticket twice, and then putting in the time to bring the field and the vendors along.

Frequently Asked Questions

What is AFE work in oil and gas?

  • AFE stands for Authorization for Expenditure. AFE work is field activity charged against an approved budget for a specific project or well, so the approvals and cost coding tied to it carry significant financial weight.

Why is manual field ticketing still a problem?

  • When field tickets are signed on paper and coded by hand, approvers often sign twice, vendors wait longer to be paid, and invoices can diverge from the agreements behind them. At scale, that means slower cycle times, slower cash, and added safety risk when signatures have to be collected in person.

What is a financial authority signature?

  • It is the approval that authorizes spend at the point the work is accepted. Capturing it electronically at the ticket level means the same signature does not have to be given again when the invoice arrives.

How does digitizing field tickets reduce invoice coding work?

  • When a coded, approved ticket flows straight into the invoice, far fewer invoices need manual coding or review downstream. The accounting team can focus on the exceptions that fall out rather than touching every document.
Enverus Press Release - Enverus honored as one of Alberta’s leading employers

The Hidden Cost of Delaying Your AI Adoption Strategy

This is the third installment in a series on AI adoption in energy. Click on the links to read the first piece on AI readiness and the second piece on AI explainability.

Every energy executive I talk to is thinking about artificial intelligence. Many are still watching and waiting for a clearer signal before they commit. It’s a natural instinct. What I’ve come to believe, after watching this play out across enough organizations, is that the waiting itself is a risk.

What Delayed AI Adoption Actually Costs

The energy companies that committed to AI adoption eighteen months ago are not only running faster–they’re running sprints instead of hurdles.

The adoption of every new tool takes time. People learn how to use it, and they incorporate it into their work, and over time they expand its use or discover new features. That’s true of AI, too. But what is also true of AI is that the more it is used the better it gets.

Every workflow running through an AI execution layer gets better with each run. Every decision reviewed and approved adds to a base of verified outcomes the system learns from. The gap between an organization that started building that foundation eighteen months ago and one starting today isn’t eighteen months. It’s eighteen months of accelerating institutional intelligence that late movers have to close while also trying to keep up with everything else.

Fundamentally, organizations still weighing AI adoption are making an operational choice, not a technological one. The companies that understood this early on were bold, but they also did the math on what waiting would likely cost.

Where Delayed AI Adoption Creates the Greatest Cost

1. Workflow Productivity

The first place the cost shows up is in the work. 

A development engineer evaluating one drilling program where they could have evaluated four isn’t falling behind because they’re working slowly. They’re falling behind because the work around the work hasn’t been automated yet. The time isn’t lost all at once. It bleeds out one workflow at a time, across hundreds of people, quarter after quarter. 

2. Institutional Knowledge and Talent

The energy industry is in the middle of a generational transition. The engineers and landmen who built decades of institutional knowledge are moving toward retirement. The organizations that have already embedded that knowledge into AI-native workflows are not only more productive today, they’re more resilient tomorrow. The ones that haven’t are watching irreplaceable expertise walk out the door with no systematic way to capture it before it’s gone.

3. AI and Competitive Advantage

In a capital-intensive industry where the difference between a good decision and a great one is measured in millions or billions of dollars, the organizations that move from analysis to action fastest have a structural advantage. Every quarter of delay is a quarter that advantage widens in someone else’s favor.

Build vs. Buy AI: What Should Energy Companies Build?

The most common reason I see organizations delay isn’t skepticism. It’s the belief that doing AI seriously means building it themselves. That belief has serious backing. Some of the most prominent voices in technology argue, loudly and often, that any company that intends to lead will build its own AI stack. For a number of our most ambitious customers, that instinct is right. They are going to build. The useful question was never build versus buy. It’s what to build, what to buy, and knowing which is which.

Here’s what I tell them: You can probably buy more than you think. The pieces that feel most proprietary are usually the ones that take years to assemble and the hardest to keep current: the data foundation, the execution layer, the workflow plumbing underneath. Buying those pieces frees your best people to do the work only your organization can do. And when you do build, build on a foundation that already understands your business so you can move fast, build powerfully, and do it economically.

There’s an honest objection to all of this. In a field moving this fast, some of whatever you build will get thrown away. That’s true, and it’s a real cost, and a visible one. But it’s the price of learning, and it’s worth paying. The cost of doing nothing never shows up on an invoice, which is exactly why it’s so easy to ignore. It’s also higher than any version of building, wasteful or not, because when you build, you’re at least learning. Standing still teaches you nothing.

The Window for AI Competitive Advantage

The energy companies that get this right in the next two years will have an advantage that is very hard to close. Not because they moved fast. Because they moved in the right direction while others were still deciding which direction to move.

The cost of doing nothing is invisible until it’s too late. But that cost is real and it grows every quarter.

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Enverus Press Release - How much production growth can North America deliver over the next decade?

Five Signs Data Maintenance Is Limiting Market Analysis

The clearest evidence often appears in the work surrounding the data: repeated searches, local mappings, corrections, checks, scheduled jobs, and handoffs that absorb time before analysis begins.

Market data can be licensed, available, and technically accessible while still requiring a surprising amount of work before anyone can use it with confidence. That work rarely sits in one place. Analysts maintain mappings. Risk teams reconcile corrected values. Data engineers support scheduled processes. ETRM administrators manage calendars and downstream delivery.

Because responsibility is distributed, each task can look routine on its own. The combined effect is harder to see. Invisible Data Work is the manual and technical preparation required before trusted data can support analysis, execution, or risk decisions.

1. Analysts search for data before they can interpret it

The first sign is a discovery process that depends on memorized data codes, internal lookup sheets, or a request to a more experienced colleague. The team may have technical access, but only a few people know how to find the correct input and confirm that it is fit for the intended analysis.

A trading and pricing team described mapping as the limiting factor in using its commodity pricing data across more analytical workflows. The data was available. The team still needed specialist knowledge to prepare it consistently for analysis.

2. Local mappings have become part of the operating model

Spreadsheets, scripts, and lookup files often begin as practical fixes. Over time, they can become an informal data layer that must be maintained whenever a provider structure, workflow, or downstream requirement changes. If no one can explain which mapping is current without asking a specific person, the organization has a dependency that deserves attention.

3. Corrections trigger a downstream investigation

A provider correction can require several follow-up steps: identify the changed value, determine which workflows received the earlier value, and move the correction into the appropriate systems. When those steps depend on manual checks or fragmented handoffs, a data change becomes a reconciliation exercise for the risk team.

Governance is stronger when corrections and supported changes are identified through the delivery process, before a downstream discrepancy forces the team to reconstruct what happened.

4. Scheduled delivery needs constant attention

Polling jobs, file movement, scheduled extracts, failed loads, and one-off requests can form a maintenance layer between provider access and downstream use. The work may be spread across IT, data engineering, analysts, and ETRM support. That makes the total cost difficult to measure even when each team understands its own part.

5. Advanced analysis still waits for prepared inputs

Commodity pricing models, valuation workflows, and AI analysis cannot compensate for unreliable market data inputs. If pricing data arrives late, requires manual validation, or differs across trading and risk systems, the team spends its time repairing the conditions for analysis. Better analytical tools increase the value of timely, consistent, governed data. They do not remove the preparation work on their own.

A practical place to begin

The useful question is not whether the work gets done. It is where the organization spends time making market data usable, which steps depend on specialist knowledge, and where data loses consistency as it moves between systems.

A Market Data Workflow Assessment maps one real workflow from provider access to downstream use. In 20 minutes, the team identifies the participants, inputs, maintenance steps, and one or two priority points where the process could be automated or simplified.

Request a Market Data Workflow Assessment

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Test of Time | Utah FORGE’s Longer Run Bears on FRVO’s Water Wall

Cape Station’s Water Profile Depends Entirely on Loss Rate | Source: EIR

Some commercial-scale enhanced geothermal system (EGS) developments rely on the assumption that reservoir water loss can be reduced to less than 1%. A new test in Utah could provide independent data on whether that level of performance is technically achievable. Fervo Energy’s (FRVO) planned 2 GW Cape Station development uses a sub-1% water-loss assumption to support development within its Milford Basin permit. The Utah Frontier Observatory for Research in Geothermal Energy (FORGE) began an extended circulation test this month at its injection-production well pair near Milford. The 90-day exercise, which could be extended to 120 days, will track “thermal breakthrough and water loss over time,” according to FORGE researchers.

Enverus Intelligence® Research (EIR) identified those issues as key technical considerations for Cape Station in its Water Wall report. The development must limit water loss to less than 1% to support 2 GW within its Milford Basin permit. No commercial enhanced geothermal system has demonstrated water loss below 1%. Fervo’s Project Red pilot, by comparison, reported water loss of about 30% over 614 operating days. Differences in reservoir geology, operating conditions and system design limit direct comparisons among projects. Still, the FORGE test could provide useful independent data on how water recovery changes during extended EGS operations.

Sage Geosystems added another data point this month after placing its 3 MW pressure-based geothermal facility near Christine, Texas, into service. The company said the facility, developed primarily for geothermal energy storage, recorded water loss below 10% across multiple operating cycles. That result was lower than the rate reported at Project Red but remained several times higher than Cape Station’s modeled target. Sage said the facility had operated for more than 120 days and that it is using the results to validate key elements of its broader approach.

EIR’s Priced for Perfection analysis also identified water loss as one of three unresolved technical considerations for Cape Station, calling the project “the real test of whether sub-1% is achievable in practice.” FORGE’s extended test could provide an early independent benchmark. Its results may help researchers and developers assess whether water recovery stabilizes during prolonged circulation and how closely experimental performance aligns with the assumptions underpinning commercial-scale EGS development.

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

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Research Highlights:

DID YOU KNOW?

Larderello, Italy just turned 122, making it the world’s oldest geothermal power plant. It started out driving a piston engine to power five light bulbs. Today the field runs 34 plants at about 800 MW.

Top Three Takeaways:

1: Why is Utah FORGE testing water loss for enhanced geothermal systems?

Some commercial-scale EGS developments, including Fervo Energy’s Cape Station, assume reservoir water loss can be held below 1% to stay within their Milford Basin permit. FORGE’s 90-day extended circulation test, which could run to 120 days, is designed to independently track thermal breakthrough and water loss over time and provide data on whether that performance level is achievable.

2: What has Fervo’s Project Red pilot shown about water loss?

Project Red, Fervo’s pilot project, reported water loss of about 30% over 614 operating days, far above the sub-1% target modeled for Cape Station. EIR notes that differences in reservoir geology, operating conditions and system design limit direct comparisons between projects, but no commercial EGS has yet demonstrated water loss below 1%.

3: How did Sage Geosystems’ facility compare on water loss?

Sage Geosystems’ 3 MW pressure-based geothermal facility near Christine, Texas, recorded water loss below 10% across multiple operating cycles after more than 120 days in service. That result beat Project Red but still ran several times higher than Cape Station’s modeled sub-1% target, and Sage is using the data to validate its broader technical approach.

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 - Until LNG demand arrives, natural gas expected to struggle at $3

Precision Power Forecasting: ERCOT 4CP Peak Day Identification in July 2026

The ERCOT Coincident Peak (CP) for July occurred during Hour Ending 18 on July 22. Enverus accurately identified the peak day one day in advance, giving customers valuable time to prepare and respond.

Earlier in the month, Enverus identified several potential CP risk days and issued a few alerts. During the final third of the month, a stronger heat wave increased the likelihood of a peak event, prompting additional CP call-outs. Ultimately, these alerts successfully identified the peak day on July 22.

Figure 1. Alert received by Enverus customers who subscribed to the 4CP alert solution, one day in advance, capturing the right peak day.

In total, Enverus issued:

  • 9 CP-day related calls throughout July

This means CP alerts were issued for 29.03% of the days during the month. On July 22, the Enverus day-ahead load forecast achieved a daily MAPE of 1.07%, compared to 1.10% for the ERCOT day-ahead load forecast. This result further validates the accuracy of our CP call issued the previous day. These results highlight the precision, responsiveness, and adaptability of Enverus forecasting tools during critical peak demand events.

Enverus Press Release - CO2 pipeline economics: The missing link

PJM’s August: a milder month that still prices tight

PJM doesn’t treat August as its hottest month, yet our summer 2026 base case sits above the market, and the bullish scenarios still carry real upside. If you’re reading August as a cooldown after July, the stack says otherwise. 

Load stays above average 

Above-average load is the base case for August, consistent with both the 2018 and 2023 analog years. The 2023 analog shows roughly 15% of the month, about five days, above 95°F in Baltimore and D.C. That’s a meaningful tail-risk scenario for a month traders often discount. 

Soil moisture deficits in the Dominion region are the amplifier to watch. If they persist, they act as a heat amplifier that supports the more bullish outcomes across the Mid-Atlantic. 

Transmission relief, but not enough to relax 

August brings some transmission relief. Otter Creek-Conistone is expected back in service, easing north-to-south pressure. PJM also postponed planned work on Brighton-Dobs and the Brighton Transformers, which relaxes flows along the I-95 corridor at the BCPEP interface. 

The net effect: August carries somewhat less transmission-driven upside risk than July. Don’t read that as a soft month. Above-average demand more than compensates, and congestion risk is already baked into the expected scenario. 

The heat rate tells the story 

Here’s the insight for anyone marking August. Last summer’s West Hub heat rate settled at 18.8. Our 2026 base case is approximately 36, against a market near 33.7. That’s a base case above market, and the bullish scenarios remain on the vertical portion of the stack, where small load surprises move price fast. 

Two structural forces support the tighter read. First, the Dominion zone re-entered RGGI, raising the marginal cost of gas generation and supporting a $1 to $3 West Hub premium in the base case, or $2 to $5 under higher RGGI price scenarios. Second, PJM’s capacity picture is unresolved. The RTEP 2034 study says the RTO is physically short in worst-case peak scenarios, while the capacity collar holds prices down for affordability. Summer 2026 is the first real-world stress test of that gap, and the 5 GW reserve threshold is the level to watch on the hottest August days. 

Get the full PJM outlook, including the transmission calendar and capacity market analysis, in our Summer 2026 Power Market Outlook. 

Enverus Intelligence® Research Press Release - Pains and Gains in the Haynesville

Show Cause, Show Later | Six ISOs Push Large-Load Reform to November

Large-Load Projects vs. Market Readiness

Unsurprisingly, all six grid operators overseen by the Federal Energy Regulatory Commission (FERC) are seeking to push their large-load tariff filings to November. FERC’s June 18 orders gave the independent system operators and regional transmission organizations 60 days to amend or justify their tariffs. The commission warned it would not grant extension requests reflexively.

The pipeline of large loads waiting to come online is concentrated in regions that are seeking more time to finalize their tariff frameworks. PJM and the MISO account for most of the identified high-confidence large load, but neither has a finished rulebook. SPP, the only region with FERC-approved large-load tariffs that the commission has pointed to as a model, has comparatively little identified capacity.

That mismatch is the central issue. Developers struggle to underwrite projects against tariffs that do not yet exist, and each delay leaves more risk unpriced. The uncertainty extends to colocated and behind-the-meter generation, both of which FERC included in its June orders. Capital does not wait for a docket. It flows into regions with known regulations and a clear barrier to entry, like ERCOT’s Batch Zero. Kicking the can down the road does not slow the buildout; it just decides where it ends up.

The real question is why the grid operators sought 90-day extensions. The simplest answer is that revising tariffs to satisfy FERC’s just-and-reasonable standard while protecting existing customers from improper cost shifting is harder than it looks. Operators may also be struggling to satisfy two audiences at once: FERC and the large-load developers deciding where to locate projects. That is the game now. Build a tariff that works for everyone or lose those loads to an operator with a more competitive one.

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

Get the Full Picture

Research Highlights:

DID YOU KNOW?

The first computer load was a grid problem too. ENIAC drew about 150 kW when it came online in 1945, enough that its operators worried about the effect on local service. A single 1 GW AI campus today pulls roughly 6,500 times that.

Top Three Takeaways:

1: Why are six ISOs asking FERC for more time on large-load tariffs?

All six grid operators FERC oversees are pushing their large-load tariff filings to November instead of meeting the original 60-day window from FERC’s June 18 orders. Revising tariffs to meet FERC’s just-and-reasonable standard while protecting existing customers from improper cost shifting is harder than it looks, and operators must satisfy both FERC and the large-load developers deciding where to locate projects.

2: Which regions have the most large-load capacity waiting on unfinished tariffs?

PJM and MISO account for most of the identified high-confidence large load, but neither has a finished tariff rulebook yet. SPP is the only region with FERC-approved large-load tariffs, the model FERC has pointed to, but it has comparatively little identified capacity waiting behind it.

3: Where is capital headed while ISOs finalize their large-load rules?

Developers struggle to underwrite projects against tariffs that don’t exist yet, so capital flows toward regions with known regulations and a clear barrier to entry, like ERCOT’s Batch Zero. Delaying tariff reform doesn’t slow the large-load buildout overall, it just decides which region ends up capturing it.

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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MISO’s August: heat eases, new gas arrives, market converges

MISO spends July breaking out, but August is different. The Great Lakes take some heat off the top, our forecast moves closer to market consensus, and new gas capacity starts reshaping South flows. Here’s what that means for your August positions.

Heat stays bullish, but the peaks soften

Above-average temperatures continue into August, consistent with both analog years. The 2023 analog shows roughly 15% of the month above 95°F across the broader region. The heat picture stays bullish.

The difference from July is the Great Lakes. That cool surface influence remains a mild moderating factor for the northern footprint, so peak loads may not reach the same sustained levels as July. You still get heat. You just get fewer of the extreme sustained peaks that define MISO’s hottest month.

Where the forecast meets the market

August is where our view converges with the market. The base case Indy Hub heat rate is approximately 23.4, against a market near 24.7, so we sit slightly below consensus. As the Great Lakes influence moderates the most extreme peaks, price formation moves toward the flatter part of the stack.

Put that in context. Last summer’s Indy Hub August heat rate settled at 15.56, reflecting a cool, wet 2025. A 23.4 base case is materially higher, and the more bullish Midwest congestion is already baked into the forecast.

Congestion has its own August signature. Bunsen-Eugene and Worthing-Morone outages come into focus. The Coco-Tipton path, which discounts to Indy on windy periods, works against Douglas-Frank, which leans bullish for Indy per Panorama modeling. That tension creates an intraday signal worth watching.

New supply changes the South

MISO is adding gas this summer, in contrast to PJM. The Orange County Advanced Power Station, roughly 1.2 GW of CCGT in a 2×1 configuration east of Beaumont, Texas, targets a June 30 COD in the Entergy footprint. Once online, it raises south-to-north power flow risk in MISO South on lighter load days, and it begins to replace the retiring Sabine unit. Magnolia Unit 2 adds more combined-cycle support in the South.

Watch the load signal too. On-peak growth is under 1%, but off-peak is approaching 2%. That off-peak figure matches the early data center pattern seen in ERCOT and PJM, where 24/7 loads show up off-peak first. MISO South has drawn real hyperscaler attention, so treat the off-peak trend as a leading indicator.

See MISO’s full price, congestion, and new-build outlook in our Summer 2026 Power Market Outlook.

Enverus Press Release - No pain, no gain: Short-term headwinds for natural gas could bring beneficial long-term tailwinds

The Obligations Sitting Unreviewed in Your Leases

Somewhere in your active lease files is a drilling obligation nobody has looked at since the day it was signed. Maybe it’s a continuous development clause. Maybe it’s a pooling restriction or a depth limit tied to a formation you weren’t producing from back then. It’s sitting there right now, lying dormant until it isn’t.

One missed clause rarely stays isolated. Spread across an active lease portfolio, it becomes dozens of obligations nobody is tracking closely, most of which will never come up. A few will, exactly when you can least afford it, with no way to know which ahead of time. Operators running an active program carry this risk every day.

Why Volume Breaks Manual Review

Manual lease review works fine when volume is low. A reviewer reads the document, understands the language, and flags what matters. The process holds up because one person can reasonably review one or a few documents thoroughly.

It stops holding up once volume grows. A trained reviewer typically spends two to four hours on a single land document, then a senior reviewer spends another 30 to 60 minutes verifying the findings. Multiply that across an active development program and the math starts working against you. There simply isn’t enough review time to give every document the same scrutiny, and coverage starts to thin as the number of documents grows.

Review Time compounds with Document volume

Then there’s the part almost nobody accounts for until it’s too late: the reviewer who knew why a particular lease carried a non-standard pooling clause eventually leaves. That knowledge doesn’t get handed off in an exit interview. It leaves with them. The next person reviewing that file starts from zero, with no history of what was flagged before or why.

Same Clause, Two Answers

Picture a set of leases across the same formation, reviewed by two different people over two different weeks. One catches a non-standard pooling restriction on an offset tract. The other, reviewing an adjacent lease with nearly identical language, doesn’t flag it the same way. Nobody did anything wrong. They just read the same kind of clause differently, on different days, with no shared record or link back to the original language to verify against.

That’s the failure pattern in most active programs. Not a single clause that slips through unnoticed for years, but ordinary reviews producing inconsistent answers to the same question, across multiple batches, with no way to see the pattern until something forces it into view.

What This Looks Like at Scale

For an operator running just one active program, this is a staffing and consistency problem: whoever reviewed the file that week decides what gets caught. But when that becomes multiple programs across several assets, the question stops being “did we catch it” and becomes “can we show who caught it, when, and why.” That’s a harder problem to solve with more reviewers. It’s an audit trail problem, which isn’t solved by adding headcount.

Where LandScape Fits Today

LandScape reads the leases your team is actively reviewing and extracts the provisions that matter: drilling obligations, pooling terms, depth and formation restrictions, royalty language, more than 15 clause types in total. Every extraction goes through review before it becomes part of the record. Nothing gets approved automatically, and nothing downstream uses a finding until your team has signed off on it.

The workflow is straightforward: upload the leases into a project, review and edit what LandScape extracts, approve it, then use the built-in chatbot to query the approved data or export it. Today that review happens at the project level, and every provision you approve becomes a verified record that links back to the exact language it came from. That extraction is built on 25 years of proprietary energy data and trained to handle the formation-specific language a generic tool wasn’t built to parse. Next on the roadmap: a single view across your entire land position, not just the batch in front of you.

The Landscape workflow

The Real Risk in Your Active Leases

The risk isn’t one dormant clause, or even a portfolio full of them. It’s obligations buried across piles of paperwork, reviewed by different people at different times, with no way to know what mattered until it’s too late to do anything but deal with it.

Find out what’s hidden in your leases. Learn more about LandScape →

Common Questions

What Is Lease Obligation Management, and Why Does It Matter?

It’s the practice of knowing what every lease in your portfolio actually commits you to, drilling triggers, pooling restrictions, depth limits, so you can prepare ahead of time. Most obligations will never become an issue, but they tend to pop up when you can least afford the surprise.

How Do You Track Obligations Across Multiple Properties?

For a single active program, that mostly becomes a resource and consistency question across your review team. Once you’re coordinating review across several asset teams, it becomes a different problem: the time and resources available to you don’t scale across volume. It becomes a real audit trail issue that isn’t solved by increasing the number of reviewers.

What Does an Effective Lease Review Process Involve with LandScape?

In practice: leases get uploaded into a project, a reviewer checks and edits what’s extracted, someone approves it, and only then does that data become part of the queryable, exportable record. Nothing moves forward without that approval step, so the process stays defensible at every stage, not just accurate on average.

What Are Practical First Steps to Put This in Place?

Start with compiling your active leases into one place instead of scattered files and individual notes. Review what gets extracted rather than trusting it blindly. Make approval a required step, not an assumption. Lastly, keep the record after the decision is made, since the next question, the next deal, or the next reviewer benefits from not starting over.

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