Texas just “slammed” the brakes on data center approvals with Governor Abbott’s “moratorium.” He’s asked ERCOT and PUCT to audit every project entering the interconnection queue on tax breaks, power, water and cooling, community impact, and ownership. But half these asks are already baked into the interconnection study, and the two that aren’t, tax breaks and community impact, don’t affect whether a project can safely connect to the grid. Meanwhile, ERCOT is already working through the existing queue via Batch Zero to speed up interconnection for projects that are ready to connect.
So who loses sleep? Nobody serious. The queue already stretches to 2050, with data centers as the single biggest driver of load growth. EIR estimates ~12 GW of high-confidence load sitting in ERCOT’s queue from data centers (FIGURE 1). Well-capitalized developers are already clearing the stringent queue requirements and won’t have any trouble getting through the audit. The ones with something to worry about are the speculative projects clogging the queue, and this audit will help clean them out. And every extra day of grid uncertainty is a nudge behind the meter, so expect this to pour fuel on BTM and co-located generation that skips the queue entirely.
This blog offers just a glimpse of the powerful analysis Energy Transition Research delivers on the trending themes. Don’t miss the full picture.
The Long and Short of Ut(ilities) – Utility Compass 3Q26 – We screen regulated utilities by comparing the market’s Gordon-implied dividend growth against the load growth we forecast in each service territory, on the thesis that demand exposure is a good predictor of earnings growth.
Class VI Update 2Q26 – Submissions Dry Up, Withdrawals Pile Up – In this quarterly report series, Enverus Intelligence® Research provides an overview of recent changes to Class VI wells associated with CCUS project in the U.S. Leveraging the Enverus FOUNDATIONS® – Carbon Innovation Wells database, we cover new Class VI applications, changes to permit status, permit approvals and newly disclosed project details.
DID YOU KNOW?
Did you know? Texas uses vastly more water raising cattle than cooling data centers, with irrigation, most of it feed for the nation’s largest herd, consuming about 9 million acre-feet a year while all U.S. data centers combined use just ~0.3% of the country’s water.
Top Three Takeaways:
1: What does Texas’s data center moratorium actually audit?
Governor Abbott has asked ERCOT and PUCT to audit every project entering the interconnection queue on tax breaks, power, water and cooling, community impact, and ownership. Half of those items are already covered by the interconnection study, and the remaining two, tax breaks and community impact, don’t affect whether a project can safely connect to the grid. ERCOT continues moving qualified projects through the queue via Batch Zero in the meantime.
2: Will the audit slow down well-capitalized data center developers?
No. Well-capitalized developers are already clearing the stringent queue requirements and won’t have trouble getting through the audit. The projects at risk are the speculative ones clogging the queue, and the audit should help clear them out.
3: How much data center load is sitting in ERCOT’s queue, and what happens if grid uncertainty grows?
EIR estimates roughly 12 GW of high-confidence data center load sitting in ERCOT’s interconnection queue, which already stretches to 2050. Every extra day of grid uncertainty nudges more developers toward behind-the-meter and co-located generation that bypasses the queue entirely.
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.
Every rate case with a data center in it eventually turns into the same argument. Are rising bills about demand, or about who’s serving it? The evidence says it’s the second one, and utilities that keep answering the first question are going to keep losing the hearing room. Virginia just gave the industry two new ways to answer the second one, in the same year.
Enverus Intelligence® Research (EIR) models Lower 48 load rising roughly 14% by 2035. That number gets read as “demand is the problem.” But almost none of that growth is organic. Organic demand is climbing about 0.5% a year. The other 13.5 points are data centers, EVs, and electrification, concentrated in a handful of markets and mostly loaded past 2030. Demand is rising fast, in the places least prepared to absorb it.
Mid-Atlantic and Northeast residential prices rose by double digits over the past year, led by a 23% jump in Washington, DC. PJM wholesale prices climbed roughly 76% over the same stretch, with the sharpest increases landing in the markets where large loads are concentrating. Virginia, the dominant data center market in PJM, is set to absorb much of the region’s projected 17 GW of new capacity through 2030.
Figure 1.High-confidence data center projects.Source: Enverus Intelligence® Research
But if demand itself were the problem, the answer is more supply, and the bill lands on everyone equally. If the problem is how a narrow slice of demand gets served and paid for, the answer is a cost-allocation tool, and Virginia just ran two of them at once.
Virginia’s Two Cost-Allocation Tools
Effective July 1, Virginia became the first state to tax data center electricity consumption directly: $0.011 per kilowatt-hour, capped at $600 million a year, with any overage refunded to operators. On the state’s existing 6 GW of capacity, that pencils out to roughly $290 million a year. Virginia kept its sales tax exemption on capital equipment intact, worth an estimated $1.9 billion annually, so the new tax targets operating cost, not the incentive to build. Amazon, which EIR identifies as accounting for all of the state’s high-confidence grid additions, carries most of that exposure.
Separately, Dominion’s GS-5 rate class, effective Jan. 2027, applies to any data center drawing more than 25 MW. Customers pay for 85% of contracted transmission and distribution capacity and 60% of contracted generation, whether they use it or not. One taxes what gets used. The other taxes what gets reserved. They are not the same instrument, and they don’t fail the same way.
Consumption tax Bills what gets used
GS-5 rate class Bills what gets reserved
Basis
Metered consumption
Contracted capacity
Rate
$0.011 / kWh
85% of contracted T&D + 60% of contracted generation
Effective date
July 1, 2026
Jan. 2027
Applies to
All data center load in Virginia
Data centers over 25 MW (Dominion)
Revenue / cost impact
~$290M/yr on existing base; capped at $600M/yr, overages refunded
Bills reserved capacity whether used or not
Source: Enverus Intelligence® Research
Which Tool Actually Holds Up
We told a version of this story in our e-book, Planning You Can Defend where AEP Ohio built a data center tariff that filtered speculative load out of its interconnection queue, and connection requests dropped roughly 50% within months. That’s a queue-filtering tool built inside a rate case. Virginia’s approach pairs a consumption tax with a separate capacity charge, aimed at cost recovery and reserved-capacity discipline rather than queue control. Same pressure but different mechanism, different state, different failure mode.
Get the mechanism wrong, and the load doesn’t just sit in the queue, it leaves. EIR projects roughly 40% of new U.S. data center capacity through 2030 will be built behind the meter on dedicated gas generation, partly to avoid congested queues and rate classes like GS-5.
For any vertically-integrated IOU watching a data-center cost-allocation fight head toward its own rate case, the question isn’t whether to act. It’s which mechanism actually holds up. A consumption tax is simple to explain to ratepayers but does nothing about speculative capacity sitting idle in the queue. A capacity-based rate class filters the queue but is harder to defend if a developer argues they’re being billed for power they never drew. Pick the wrong one and you’ve built your next intervenor’s opening argument for them.
Is Your State Next?
Virginia won’t be the last state to try a cost-allocation fix, and it’s already running two at once. If you’re heading into a rate case where data centers are the flashpoint, our analyst team can benchmark your state’s approach against what’s actually holding up in Virginia, Ohio, and the other states EIR is tracking, before you’re the one defending it in front of a PUC.
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.
GEV’s gas turbine backlog climbed to 116 GW in Q2, up from 100 GW in the prior quarter as utilities, independent power producers (IPPs) and data center developers continue securing generation equipment years in advance. Turbine demand has intensified to the point that the supplier is now sold out until 2031 for deliveries.
The growing backlog strengthens the position of existing gas-fired generation. Equipment lead times are one element of drastic increases in new build CCGT costs, up more than 2x since 2020. It is becoming increasingly difficult to build new CCGTs. In ERCOT’s current market, a highly efficient CCGT requires a PPA of ~$70/MWh to achieve bankable returns, while the same asset in PJM requires a capacity price upwards of $400/MW-day.
This trend is also reflected in secondary markets who have seen similar levels of inflation in the price paid for operational assets, which continue to transact at approximately ½ that of replacement costs (Figure 1). The build-vs-buy dilemma remains tilted toward acquisitions. For companies seeking exposure to near-term load growth, purchasing existing generation remains the more attractive path.
This blog offers just a glimpse of the powerful analysis Energy Transition Research delivers on the trending themes. Don’t miss the full picture.
Cheaper To Buy | CCGT Replacement-Cost Wedge – We examine the widening replacement-cost wedge between new combined-cycle gas turbine (CCGT) facilities and acquisitions of existing gas-fired power plants.
PJM RBP | Buying Capacity for Load at Risk – This report outlines our view of PJM’s proposed Reliability Backstop Procurement, including the projects and technologies likely to participate and the program’s expected impact on capacity prices.
DID YOU KNOW?
The company has an installed base of over 7,000 gas turbines and around 55,000 wind turbines, which together produce about 25% of the world’s electricity.
Top Three Takeaways:
1: How large is GEV’s gas turbine backlog, and when are deliveries available?
GEV’s gas turbine backlog climbed to 116 GW in Q2, up from 100 GW in the prior quarter. Demand from utilities, independent power producers (IPPs) and data center developers has intensified to the point that the supplier is now sold out until 2031 for deliveries.
2: Why is building a new CCGT so difficult today?
New CCGT costs have risen more than 2x since 2020, with equipment lead times a key driver of that inflation. In ERCOT’s current market, a highly efficient CCGT requires a PPA of approximately $70/MWh to achieve bankable returns, while the same asset in PJM requires a capacity price upwards of $400/MW-day.
3: Why does the build-vs-buy dilemma favor acquiring existing gas assets?
Operational assets continue to transact at approximately half of replacement costs. With new CCGT economics strained by supply chain constraints and rising prices, purchasing existing generation remains the more attractive path for companies seeking exposure to near-term load growth.
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.
Oracle’s Project Jupiter has hit a serious regulatory roadblock, as the New Mexico State Land Office recently denied a gas pipeline application meant to deliver fuel for the Bloom Energy (BE) fuel cells powering the data center. It’s an additional setback for the site, which still lacks an air permit.
BE has been the darling of behind-the-meter power, promising a time-to-power premium, in some cases as little as 55 days, alongside lower emissions through its combustion-less technology. That hype has translated to a monumental 1,100% Y/Y share price appreciation, as BTM load continues to grow.
The fundamentals remain compelling, but BE must execute on its ~$20B product backlog to justify current valuations. EIR research has flagged that execution risk and customer concentration pose legitimate threats to the company. Oracle currently represents nearly 70% of named backlog (Figure 1), siphoning BE’s success into a single developer and its ability to build projects. This recent delay confirms our concerns: execution, not demand is the real risk to the story and Project Jupiter is the first crack to show.
This blog offers just a glimpse of the powerful analysis Energy Transition Research delivers on the trending themes. Don’t miss the full picture.
PJM RBP – Buying Capacity for Load at Risk – We outline EIR’s view of PJM’s proposed Reliability Backstop Procurement, including the projects and technologies likely to participate and the program’s expected impact on capacity prices.
Nuclear PPA Screening – Identifying Prime Candidates for Hyperscaler Offtake – This report screens operating U.S. nuclear plants with uncontracted capacity to identify the strongest candidates for long-dated hyperscaler PPAs, ranking assets by plant quality, contractable capacity, life-extension potential, ownership and data center demand exposure.
Bloom Energy – Strong Fundamentals, Little Room for Error – EIR forecasts ~62 GW of new U.S. data center capacity through 2030, with ~40% going behind the meter on dedicated gas as operators race ahead of grid interconnection timelines.
DID YOU KNOW?
Fuel cells are older than the light bulb, invented in 1839!
Top Three Takeaways:
1: What regulatory setbacks are Oracle’s Project Jupiter facing in New Mexico?
Oracle’s Project Jupiter has hit a serious regulatory roadblock after the New Mexico State Land Office denied a gas pipeline application meant to deliver fuel for the Bloom Energy fuel cells powering the data center. The site also still lacks an air permit, making this denial an additional setback in an already delayed permitting process.
2: What has driven Bloom Energy’s 1,100% year-over-year share price appreciation?
Bloom Energy has become the darling of behind-the-meter power by promising a time-to-power premium, in some cases as little as 55 days, alongside lower emissions through its combustion-less technology. As BTM load continues to grow, the market has rewarded that proposition with a monumental 1,100% year-over-year share price appreciation. The fundamentals remain compelling, but executing on its approximately $20 billion product backlog is what must justify current valuations.
3: Why does execution risk pose the greatest threat to Bloom Energy’s investment story?
EIR research has flagged that execution risk and customer concentration pose legitimate threats to Bloom Energy. Oracle currently represents nearly 70% of named backlog, concentrating BE’s success in a single developer and its ability to build projects. This recent pipeline denial confirms those concerns: execution, not demand, is the real risk to the story, and Project Jupiter is the first crack to show.
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.
The demand signal is real: hyperscalers are building at a pace the grid was not designed to supply, and the gap between what utilities can deliver and what data center developers need is widening by the quarter. That gap is becoming a gas story.
Grid interconnection queues are years long in most regions. Permitting timelines compound the problem. Faced with those constraints, a growing share of new data center capacity is moving toward behind-the-meter (BTM) generation with dedicated on-site gas turbines that sidestep the grid entirely and pull fuel directly from the supply chain. Enverus Intelligence® Research (EIR) estimates BTM generation could require over 1.3 Bcf/d of incremental natural gas demand by 2030 in the base case, with ERCOT and PJM together accounting for roughly half of that. The map below shows where high-confidence BTM and grid-connected projects are concentrated today.
Figure | High-Confidence Data Center Projects — EIR 2Q26 Data Center Capacity Forecast
Source: Enverus Intelligence® Research, 2Q26 Data Center Capacity Forecast | Off the Grid, on the Gas (June 2026)
The geography matters, as projects are concentrated in PJM, ERCOT, MISO, and WECC, with Texas and the mid-continent emerging as particularly active corridors for BTM development. That distribution maps closely to where Permian and Haynesville gas can potentially flow.
How Data Center Power Demand Is Creating New Gas Supply Opportunities for E&P Operators
Upstream operators are right to see this as an opportunity. The commercial logic is straightforward: contracted offtake at a fixed price, elimination of basis risk, and in some cases, the ability to capture a margin on power rather than just gas. Chevron’s agreement to supply a Microsoft data center in Reeves County, Texas, under a 20-year power purchase agreement is a concrete example of how this is already playing out in the Permian.
But the opportunity is not equally available across basins, and that is where operators need to think carefully. EIR research has tracked a fundamental reshuffling of the U.S. gas supply stack as Permian associated gas volumes grow. The market is no longer treating Permian supply growth as a risk to manage; it is treating it as a structural reality to build around, reflected in a steady cadence of new pipeline proposals. That creates both opportunity and competitive pressure. Basins that cannot demonstrate reliable takeaway to key demand corridors will find themselves at a pricing disadvantage, even if their production economics are strong.
Why Pipeline Takeaway Capacity Determines Which Basins Win Data Center Gas Supply Contracts
Appalachia illustrates this dynamic clearly. For years, abundant production and constrained egress held regional basis at a persistent discount. That is now changing as pipeline additions and debottlenecking projects ease congestion into key demand corridors, with EIR research suggesting the forward curve is underestimating how quickly improved takeaway could lift Appalachian pricing toward structural improvement. The lesson is not specific to Appalachia. Any basin where supply outpaces egress faces the same pricing ceiling, regardless of productive capacity.
For E&P operators evaluating the data center supply opportunity, the practical question is: can your gas actually reach the load? That means understanding which pipelines exit your basin, how utilized those corridors are today, what competing flows (LNG export, industrial demand, other producers) are claiming remaining capacity, and which market hubs your gas can access at competitive pricing.
Operators who can answer those questions with current, meter-level transmission data are in a meaningfully different position than those who cannot. They can assess whether a proposed supply agreement is serviceable before committing. They can negotiate transport contracts with visibility into where capacity is available. They can identify which hub routes offer pricing upside rather than basis discount.
What E&P Operators Need to Know Before Signing a Data Center Gas Supply Agreement
Data center developers are not waiting. Their build timelines are set by their own infrastructure commitments, and the operators who can bring both supply and transmission clarity to the conversation are the ones closing deals. The Permian and Haynesville operators moving fastest on this are not necessarily the ones with the most gas; they are the ones who understand their basin’s position in the supply chain well enough to make a credible, bankable offer.
Production is the starting point. Deliverability is the differentiator.
Key Takeaways for Operators Supplying Gas to Data Centers
Production volume alone does not determine basin competitiveness. The operators winning data center supply agreements are those who can demonstrate reliable deliverability, not just wellhead output. Takeaway capacity, hub access, and corridor utilization are the variables that matter in commercial negotiations.
The Permian supply stack is reshuffling the national market. Growing Permian associated gas is no longer a risk to manage — it is a structural reality being built around, with new pipeline proposals reflecting that shift. Basins without strong egress will face pricing pressure regardless of their productive capacity.
Appalachia is a leading indicator for every constrained basin. Years of abundant supply with limited egress created persistent basis discounts. Improving takeaway changes pricing dynamics faster than the forward curve typically anticipates. Every basin with constrained exit capacity faces the same structural ceiling.
Operators need meter-level transmission visibility before signing supply agreements. Understanding pipeline utilization, competing flows, and hub pricing on a daily basis is what separates operators who close bankable deals from those who commit without fully understanding the constraints.
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.
For financial institutions financing, investing in or valuing power-intensive projects, the rules governing large-load interconnections are becoming a material consideration for project timing, capital requirements and portfolio strategy.
Electricity demand from data centers, advanced manufacturing and other large industrial users is growing faster than many transmission systems were designed to handle. On June 18, 2026, the Federal Energy Regulatory Commission (FERC) issued show-cause orders directing all six regional grid operators to justify or reform their tariff rules for large-load interconnections within 60 days and file resource adequacy reports within 30 days.
These are not final rules. They open six parallel regional proceedings, and outcomes will likely vary by market. But the direction is unmistakable: FERC wants large-load projects to connect more efficiently, bear an appropriate share of the costs they create and demonstrate a credible relationship between new demand and available supply.
For lenders and investors, that means regulatory decisions could directly affect development timelines, financing needs, asset valuations and long-term portfolio strategy.
Read the Full Intelligence Report
What does FERC’s June 2026 large-load order mean for each RTO/ISO, and which are best positioned to connect large loads fast? Enverus Intelligence® Research breaks down the regulatory landscape, regional readiness gaps, and market implications in detail.
What FERC’s Large-Load Order Means for Energy Investors
FERC is not simply trying to make it easier for more large loads to connect to the grid. It is attempting to establish clearer terms for how those projects enter the system, who bears the associated costs and how new electricity demand will be matched with reliable supply.
For energy lenders and investors, that means interconnection is moving out of the technical appendix and into the center of the investment decision. Regional differences will matter — lenders and investors should expect different requirements, risks and opportunities across the country as each grid operator responds to the order.
The projects most likely to attract capital will not necessarily be those with the largest announced demand. They will be the projects that can demonstrate a credible, flexible and financeable path to power.
What These Changes Mean Together
FERC’s proceedings point toward a new model for large-load development, a model that demands more from projects before they can access the grid. Going forward, developers will increasingly be expected to demonstrate greater commercial readiness, clearer responsibility for grid costs, a realistic source of generation, operational flexibility where applicable and meaningful coordination between load, generation and transmission timelines.
For financial institutions, this redefines what project bankability means. Strong demand signals are not enough. A financeable project needs credible answers to five specific questions and those answers will vary across the six regional markets affected by the FERC order.
Figure 1: The five questions that define project bankability under the new FERC framework.
Here Are the Five Changes Investors Need to Understand
Figure 2: FERC’s five pillars of large-load interconnection reform, issued June 18, 2026
1. Faster and More Disciplined Study Processes
FERC is directing regional grid operators to overhaul how large-load transmission applications are submitted, evaluated and studied, including consideration of alternative transmission technologies that could expand grid capacity more efficiently.
According to Enverus Intelligence® Research (EIR), the goal is to create a process that can distinguish credible developments from speculative, duplicative, or commercially unready requests. Projects that are genuinely ready may move through faster; less mature applications could lose their place in the queue or face higher requirements.
Why this matters for financial services
A utility interconnection application or a proposed energization date should not be treated as evidence that power will actually be available. Before committing capital, lenders and investors should evaluate:
Whether the developer controls the site and has made meaningful financial commitments
Which interconnection studies have been completed — and which are still outstanding
What network upgrades are required and whether the proposed timeline accounts for them
Whether the load request reflects a realistic development schedule, not just an option
The core financial question:
Is this a real project with an executable path to power — or an attractive development story that hasn’t been stress-tested against grid realities?
2. Stronger Protection Against Cost Shifting
FERC is focused on bringing transparency to transmission and network upgrade costs by ensuring those costs are borne by the projects that trigger them, not shifted to utilities and existing ratepayers.
A new data center or industrial facility can require substantial grid investment. If that project is delayed, downsized or canceled, the infrastructure built to serve it may still need to be paid for. FERC wants clearer accountability for those outcomes.
ENVERUS INTELLIGENCE RESEARCH®
EIR notes that utilities stand to gain significantly from the volume of transmission buildout this reform will drive. EIR specifically identifies AEP, Oncor and NextEra Energy (NEE) as well-positioned to capitalize — all three are concentrated in PJM and ERCOT, where EIR forecasts the highest load growth. Source: ”Setting Terms | FERC Rewires Large-Load Interconnection,” EIR, June 22, 2026.
Why this matters for financial services
Large-load developments will increasingly require meaningful financial commitments earlier in the project lifecycle. Depending on how regional rules evolve, exposure could include:
Study deposits and scoping fees
Network upgrade contributions and construction cost-sharing obligations
Letters of credit and parent company guarantees
Minimum payment requirements and obligations tied to requested capacity
Costs associated with a delayed or reduced load ramp
These requirements will affect project leverage, liquidity, contingency reserves and the amount of sponsor equity required before operations begin. Transmission costs are becoming a material line item in the project capital structure.
Figure 3: Financial commitments now arise at every stage of the project lifecycle, not just at construction.
3. Greater Support for Co-location and Behind-the-Meter Generation
FERC is directing regional markets to develop clearer treatment of co-located projects — arrangements that pair a large electricity user with generation located on or near the same site. Under the new order, these projects receive an explicit regulatory tailwind: they are positioned to become the preferred pathway for connection requests.
ENVERUS INTELLIGENCE RESEARCH®
EIR views co-location as the emerging blueprint for large-load development. According to EIR, co-located projects — already a major and growing trend — now receive regulatory validation, paving the way for projects that pair load with supply to become the desired model. EIR tracks co-located data center campuses across all major grid regions and expects this structure to increasingly define how hyperscalers and industrial users access power. Source: “Setting Terms | FERC Rewires Large-Load Interconnection,” EIR, June 22, 2026.
That said, co-location changes the nature of the risk; it doesn’t eliminate it. The entire power solution still requires rigorous diligence.
Why this matters for financial services
For gas-fired behind-the-meter generation, diligence should cover pipeline proximity, available transportation capacity, fuel price exposure, equipment availability, air permitting, operating reliability, backup power and grid import/export restrictions.
For renewable and storage combinations, the analysis should address intermittency, storage duration, grid backup requirements and contractual alignment with the facility’s actual operating profile.
Co-location also opens new investment opportunities across generation, storage, microgrids, gas infrastructure and related energy services.
Figure 5: Traditional grid connection vs. co-located/BTM generation — risk profile and regulatory treatment.
4. New Service Options for Flexible Large Loads
FERC is asking grid operators to consider new transmission-service options for large loads that can reduce or interrupt consumption when the grid is constrained. Projects with genuine operational flexibility may be able to connect faster, or at lower cost, because they don’t require the grid to serve their full maximum demand under every condition.
This is particularly relevant for projects supported by on-site generation, battery storage, staged load growth, demand-management technology, or curtailable operations.
Why this matters for financial services
Load flexibility can be a real source of project value — but only when it is technically credible and commercially structured. Before underwriting that value, investors should ask:
How often can the project be curtailed and for how long?
Who controls the curtailment decision — the utility, the operator, or an automated system?
Does the project have backup supply that maintains operations during interruptions?
Are tenant or customer contracts compatible with service interruptions?
What happens to revenue during a curtailment event?
The core financial question:
Can the project reduce its grid demand without undermining the revenue and operating assumptions that support the investment thesis?
5. Better Coordination Between Large Loads and Nearby Generation
The final reform area addresses how new generating facilities should be studied when they are intended to serve electrically proximate or co-located large loads. Historically, load development, generation interconnection and transmission planning have moved through separate processes on different timelines — a separation that is increasingly untenable when a large-load project depends on new generation arriving at roughly the same time.
Why this matters for financial services
Investors can no longer evaluate the load and its proposed power supply as independent projects. The two must be underwritten together. Key questions include:
Does the generation project have its own credible interconnection path?
Are transmission upgrades required for both the load and the generation?
Can the generation legally and physically serve the load as proposed?
How do delays in one project affect the economics of the other?
Who bears the risk if the load and generation timelines don’t align?
This is especially important for projects promising accelerated access to power through a generation asset that hasn’t yet been constructed or interconnected. As EIR puts it, a proposed power source is only valuable when it can actually be delivered on the timeline embedded in the financial model.
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.
As we move through the summer months and solar production becomes increasingly important to power market operations, forecasting accuracy plays a critical role in helping market participants prepare for volatility and manage risk. With this in mind, we reviewed the performance of the Enverus day-ahead solar forecast across the two U.S. ISOs with the highest solar generation: ERCOT and CAISO.
The Enverus day‑ahead STPF solar generation forecast outperformed ISO forecasts across the two ISOs with the highest solar generation during the May–June 2026 period (using day‑ahead rolling forecasts published at 8 AM). The strongest improvements were observed during periods of elevated weather-driven variability, including heat waves and significant cloud-cover events, where ISO forecasts exhibited considerable bias. Table 1 summarizes total MAE and CAP_MAE for Enverus forecasts versus ISO forecasts, with Enverus outperforming the ISOs in every month analyzed.
Region/ISO
Month
Total MAE (MW)
Cap_MAE (%)
Enverus
ISO
Enverus
ISO
ERCOT
May
1214.05
1221.95
3.54
3.57
ERCOT
June
1144.8
1403.28
3.34
4.10
CAISO
May
971.43
1081.56
4.22
4.70
CAISO
June
708.64
930.02
3.08
4.04
Table 1. Total MAE: May–June 2026
Extreme Weather Period Analysis
The Enverus STPF (Short-Term-Production-Forecast) forecast demonstrated its largest performance advantage during periods of challenging weather conditions, including the late-June ERCOT heat wave and an early-May CAISO solar generation decline associated with extensive cloud cover.
ERCOT Heat Wave (June 18-30, 2026)
ERCOT experienced a prolonged heat wave from June 18–30, with peak system demand approaching 82 GW on multiple days. During this 13-day period, the Enverus day-ahead solar forecast achieved an MAE of 1,060.64 MW, substantially outperforming the ISO forecast MAE of 1,704.50 MW. Enverus delivered lower forecast error on 12 of the 13 days analyzed. During this event, the ISO forecast consistently overestimated solar generation, while the Enverus forecast more accurately captured the solar generation pattern.
Period
Total MAE (MW)
Cap_MAE (%)
Enverus
ISO
Enverus
ISO
June 18 – June 30
1060.64
1704.5
3.10
4.98
Table 2. One day‑ahead ERCOT system‑wide solar forecasts vs. ISO
Figure 1. Enverus Mosaic proprietary platform (data displayed in Hour Beginning), evolution of the Enverus solar forecast between June 18 and 30, 2026 against ERCOT’s forecast and actual solar generation. The Enverus Mosaic short-term analytics and forecasting solutions have a 25-year track record of forecasting load and renewables more accurately than the ISOs.
CAISO Low Solar Output Event (May 5–6, 2026)
CAISO solar generation declined significantly on May 5–6 relative to surrounding days. Weather conditions across portions of California during this period included widespread marine-layer cloud cover and overcast conditions, which likely contributed to the reduction in solar output. Across the two-day event, the Enverus day-ahead solar forecast achieved a combined MAE of 411.29 MW, substantially outperforming the ISO forecast MAE of 1,628.98 MW. Enverus delivered lower forecast error on both days analyzed. The ISO forecast significantly overestimated solar generation during the event, particularly on May 6, whereas the Enverus forecast more accurately anticipated both the magnitude and timing of the reduction in solar output.
Period
Total MAE (MW)
Cap_MAE (%)
Enverus
ISO
Enverus
ISO
May 5
306.58
1294.35
1.33
5.62
May 6
516.01
1963.60
2.24
8.53
Table 3. One day‑ahead CAISO system‑wide solar forecasts vs. ISO
Figure 1 illustrates the sharp decline in CAISO solar generation on May 5–6, followed by a recovery beginning on May 7. The Enverus forecast accurately anticipated the magnitude of this decline compared to the ISO forecast, resulting in substantially lower forecast error during the event.
Figure 2. Enverus Mosaic proprietary platform (data displayed in Hour Beginning), evolution of the Enverus solar forecast between May 4 and 7, 2026 against CAISO’s forecast and actual solar generation. The Enverus Mosaic short-term analytics and forecasting solutions has a 25-year track record of forecasting load and renewables more accurately than the ISOs.
ERCOT 4CP Call-Out – June 2026
The Coincident Peak (CP) in ERCOT for June occurred during Hour Ending 18 on June 18. Enverus accurately identified this interval one day in advance, giving customers valuable time to prepare and respond.Earlier in the month, our latest demand forecasts and analysis indicated that the peak demand was more likely to occur during the second half of June. As a result, we did not issue any CP alerts at the early beginning of the month.
Figure 3. Alert received by Enverus customers who subscribed to the 4CP alert solution, one day in advance, capturing the right peak hour.
In total, Enverus issued:
5 CP-related calls throughout June
Covering 8 high-demand hours
This means we issued calls for 16.67% of the days, and just 1.11 % of the total hours of the month of June.
On June 19, the Enverus day-ahead load forecast achieved a daily MAPE of 1.12%, compared with 1.76% for the ISO day-ahead load forecast, reinforcing the accuracy of our CP call made the previous day. These results highlight the precision and adaptability of our forecasting tools.
Conclusion
Across both renewable generation and load forecasting applications, Enverus day-ahead forecasts consistently demonstrated superior accuracy relative to ISO forecasts during May and June 2026.
The performance advantage was particularly evident during periods of elevated weather-driven volatility, including the late-June ERCOT heat wave and the early-May CAISO solar generation reduction. In ERCOT, Enverus successfully identified the June Coincident Peak one day in advance with very few calls. The strong performance of the day-ahead load forecast during this period further reinforced the reliability of the forecasts used to support CP decision-making.
These results demonstrate the value of our forecasting tools and analysis, particularly during high‑volatility periods, ultimately supporting improved market outcomes, risk management, and peak-demand response strategies across North American power markets.
Note: CAP_MAE represents the Mean Absolute Error (MAE) scaled by the maximum observed value (CAP) in the dataset. This scaling produces a relative error measure, ensuring that the system’s overall scale and the magnitude of values during the evaluation period do not distort the error metric.
The first half of 2026 brought commodity price volatility, geopolitical disruptions, infrastructure constraints, and demand patterns that don’t match the forecasts written just a few years ago. Our Mid-Year Minerals Outlook webinar highlights what’s happening and what it means heading into the second half of the year.
If you missed it, the replay is available now. Here’s a preview of what the session covered.
What’s driving commodity prices right now
Energy markets respond to events, not just supply and demand fundamentals. The webinar opened by grounding the discussion in that reality: conflicts, infrastructure failures, weather events, and policy surprises all redirect long-term trajectories. Understanding the forces behind current pricing is the starting point for making sound decisions about your portfolio.
Energy demand is growing, just not where you might expect
Global primary energy demand continues to increase, but the growth rate has slowed and is not uniform across geographies. Where that growth is concentrated, and what it means for different commodity types, came through clearly in the session. It’s a more nuanced picture than the headline numbers suggest.
For mineral owners, the geographic distribution of demand growth has real implications. Markets where consumption is expanding fastest are also the markets driving LNG trade flows, pipeline investment decisions, and ultimately the price signals that operators respond to when setting their drilling budgets.
Natural gas vs. oil: a different outlook for each
The webinar draws a clear distinction between where natural gas demand is headed versus oil. The dynamics affecting each are different enough that your exposure to one versus the other carries different implications for long-term cash flow. Renewables growth, energy transition timelines, and transportation trends are all part of the picture, and they don’t point in the same direction for both commodities.
If your acreage is weighted toward natural gas, or you’re evaluating an acquisition with significant gas production, the session offers a grounded view of where the market is heading and what to make of the current price environment. The same applies if you’re oil-weighted and thinking through how long that exposure stays constructive.
What export infrastructure has to do with your royalties
Production in the ground is only worth what you can actually sell. Getting gas or oil from the wellhead to a buyer requires pipelines, processing facilities, and for natural gas crossing borders, export terminals that take years to permit and build. When that infrastructure isn’t there, or isn’t keeping pace with production growth, royalty owners feel it in their checks.
The webinar covers where those bottlenecks are right now, how they developed, and what the near-term outlook looks like for resolving them. If you own acreage in a basin where prices have been running below what you expected, or you’re evaluating a deal and trying to understand why one area prices lower than another, this section gives you the context to read those signals more clearly.
What this means if you’re managing or evaluating minerals
Mineral and non-op interests don’t exist in isolation. Commodity prices are shaped by infrastructure capacity, geopolitical events, demand patterns across global markets, and technology adoption curves that are still playing out. The session closes with a practical lens for thinking about your acreage and royalties heading into the second half of the year.
Three questions the webinar answers:
How does the commodity mix in your royalties or acreage align with where demand is actually heading?
For natural gas interests, is your acreage close enough to the infrastructure needed to capture full market value?
How are the operators on your acreage responding to current price conditions, and what does that mean for near-term development activity?
Some Eagle Ford acreage once considered uneconomic is back on development plans. In the recentEnverus Intelligence® Research webinar, Basin Insights: Eagle Ford Long Laterals, horseshoe well data showed why operators are taking a fresh look at these areas.
Historically, irregular lease boundaries, split ownership, and easements made certain acreage difficult to develop. Traditional two-well pads require space for straight laterals and vertical sections, leaving many tracts untouched. Horseshoe well designs change that equation by allowing operators to develop acreage that previously would have been left behind.
What Horseshoe Wells Solve in Eagle Ford
A horseshoe well drills out, turns, and comes back, covering roughly the same lateral footage as two straight wells but with a single vertical section instead of two. That’s the entire idea. It sounds simple because it is. What makes it worth writing about is where operators are choosing to drill them: acreage blocks with irregular shapes, split ownership, or lease geometry that made a standard two-well layout impossible to permit cleanly.
Crescent Energy has drilled more horseshoe wells in the Eagle Ford than any other operator, and roughly 60% of its horseshoe results are in hand. The rest are sitting in permit or drilled-but-uncompleted status, which means the current data set is a partial picture of a technique that’s still filling in. ConocoPhillips has also moved horseshoe designs into active development programs, so this isn’t a single-operator experiment anymore. It’s becoming a standard tool for a specific acreage problem.
That timing matters for how you read the results so far. Enough horseshoe wells are producing to draw real conclusions about cost and productivity, but the picture isn’t complete. Operators evaluating their own acreage right now are working with a data set that’s still growing, which means the case for or against a given parcel can change as more of Crescent’s results and other operators’ programs come online.
Horseshoe Well Economics: Why the 15% Cost Savings Matters
Avoiding a second vertical section cuts drilling costs by around 15% compared to two independent short laterals. That’s the number operators cite most often in the Eagle Ford. Chord Energy has reported closer to 30% savings on horseshoe wells in the Bakken, where longer average laterals mean the fixed cost of a second vertical section represents a bigger share of total well cost.
The gap between those two numbers is worth exploring. It tells you the savings scale with how much lateral footage you’re already committing to, not just the fact of skipping a vertical section. In a basin like the Eagle Ford, where laterals run shorter than the Bakken on average, 15% is the more realistic planning number. Still, on a play where breakevens have been climbing as Tier 1 inventory thins out, that 15% cost reduction on a location that otherwise wouldn’t get drilled at all is a meaningful swing in a development plan’s economics.
What The Karnes County Data Shows
ConocoPhillips ran a stacked horseshoe program in Karnes County, drilling across two Lower Eagle Ford intervals and an Upper Eagle Ford interval on the same pad. Early initial production rates came in ahead of the subplay average. That result matters for a specific reason: it shows horseshoe geometry works across multiple stacked intervals, not just as a single-zone solution for oddly shaped acreage.
That distinction changes how a team should evaluate the technique. A horseshoe well isn’t only a land-driven decision about fitting a lateral into an awkward parcel. It’s also a completions decision about which intervals a given block can support, since the Karnes County results suggest stacked horseshoe development doesn’t sacrifice per-well productivity to gain the cost advantage.
Average horseshoe lateral length in the Eagle Ford runs around 10,000 feet. That’s long enough to justify the well design economically while staying within what current drilling equipment handles reliably on a single run.
Horseshoe Well Spacing Limits and Acreage Constraints
Horseshoe wells aren’t free of constraints, and the constraint that matters most is interwell spacing. Most current activity clusters around 1,300 feet between the outbound and return legs, which gives operators a cushion against wellbore collision risk and pressure interference between the two legs. Tighter spacing is possible within the Eagle Ford core, where the tightest horseshoes drilled so far have come in around 800 feet.
That spacing requirement is also what limits which acreage blocks qualify. A horseshoe well needs enough width to turn within, so this isn’t a fix for every stranded parcel. It’s a fix for parcels with awkward shape but adequate width, which is a narrower category than “anything that wasn’t drillable before.” A block that’s simply too narrow still doesn’t work, no matter how much the shape otherwise fits the technique.
This is where a land team’s early screening matters more than drilling engineering does. Getting the spacing wrong on paper means either walking away from a location that would have worked or committing engineering time to a parcel that was never going to clear the technical floor.
What This Means For Development Planning
Horseshoe wells are reshaping which parcels make it into a development plan, as operators revisit acreage they’d previously ruled out. Locations that got written off because a two-well pad wouldn’t fit the lease geometry are back on the table, provided the parcel has the width a horseshoe design needs. For operators sitting on Eagle Ford positions with irregular boundaries, that’s a direct change to how much of the acreage position counts as real inventory, not a paper adjustment to a type curve.
Finding The Right Candidates to Drill
The hard part is finding those locations. Most teams don’t have a clean way to overlay lease geometry against the spacing thresholds a horseshoe design requires, so the screening ends up happening well by well, usually after someone already suspects a parcel might qualify. Locations that would clear the technical floor can sit unevaluated simply because nobody flagged them first.
Enverus PRISM® lets you pull lease geometry, existing horseshoe results, and spacing data into one view, so you can flag which of your undeveloped locations qualify for the design before committing engineering time to a full evaluation. That turns a parcel-by-parcel search into a filtered list your land and engineering teams can work from together.
The data set on horseshoe wells is still growing. Crescent alone has 40% of its results still to come in, and Karnes County is one case study among a technique that’s spreading to more operators and more counties. Watch the Eagle Ford webinar for the full breakdown of horseshoe economics, spacing data, and the extended laterals story shaping the rest of the basin’s development plans.
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.
ChargePoint and Florida-based Optimus Energy Solutions are expanding their partnership to deploy more than 200 public fast-charging ports across the Southeast, targeting quick-service restaurants and retail centers. ChargePoint will serve as the exclusive provider of hardware, software and services, while Optimus will own and operate the sites.
The buildout comes as Enverus Intelligence® Research (EIR) projects a widening regional divide in EV adoption, with much of the Southeast lagging behind states with zero-emission vehicle mandates. Florida is a notable exception, ranking seventh nationally in projected 2035 EV penetration (Figure 1), driven by its large vehicle base, higher-income households and strong adoption in major metropolitan areas rather than policy. EIR recently cut its 2035 U.S. EV penetration forecast to 8.1% from 20%, citing slower consumer uptake and the September 2025 expiration of federal EV purchase credits under the One Big Beautiful Bill Act. The outlook reinforces the view that adoption in non-mandate states will hinge more on infrastructure and structural demand than on policy.
This blog offers just a glimpse of the powerful analysis Energy Transition Research delivers on the trending themes. Don’t miss the full picture.
Cheaper To Buy | CCGT Replacement-Cost Wedge – We examine the widening replacement-cost wedge between new combined-cycle gas turbine (CCGT) facilities and acquisitions of existing gas-fired power plants.
Bloom Energy | Strong Fundamentals, Little Room for Error – We assess whether BE’s order backlog and manufacturing capacity can support the revenue implied by its valuation, while evaluating its path to lower production costs through 2030.
Electric cars predate gas-powered vehicles by decades and once outsold them in the U.S. around 1900 before Ford’s Model T made gasoline cars affordable enough to dominate.
Top Three Takeaways:
1: Why is ChargePoint expanding charging infrastructure in the Southeast despite slower EV adoption forecasts?
The expansion reflects the growing importance of charging availability in driving EV adoption. As federal incentives fade and consumer uptake remains slower than expected, accessible public charging infrastructure will play a larger role in supporting EV growth, particularly in regions that are not relying on policy mandates.
2: What makes Florida stand out in the Southeast EV market?
Florida is projected to rank seventh in the nation for EV penetration by 2035, making it a regional leader despite lacking a zero-emission vehicle mandate. Its large vehicle population, higher-income households and strong adoption in major metro areas are expected to drive EV growth through market demand rather than regulation.
3: What does this partnership signal about the future of EV adoption in non-mandate states?
The ChargePoint and Optimus partnership highlights a shift toward infrastructure-led growth. With EIR lowering its U.S. EV penetration forecast, success in states without EV mandates is likely to depend more on the availability of convenient charging networks and underlying consumer demand than on government incentives or policies.
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.
Let’s get started!
We’ll follow up right away to show you a quick product tour.
Let’s get started!
We’ll follow up right away to show you a quick product tour.
