1 | Regulators are slowing and repricing grid-connected load, so permission decides where data centers get built. Rising electricity bills are being attributed to data center load growth. Add in AI safety concerns, and I think data center development and cost allocation will remain a focus for regulators and policymakers beyond the midterms, ERCOT’s Batch Zero process and FERC’s show-cause orders.

2 | Developers are going behind the meter in phases, with premium off-takers paying for the speed that merchant economics cannot fund. We think of data centers as premium off-takers: buyers that value speed to power and have a business model that can support premium power contracts. The pull to BTM gets stronger when regulation and policy push grid-connected timelines to the right, when a new-build merchant CCGT needs about $500/MW-day of PJM capacity or a $70/MWh ERCOT contract, both above where markets clear today, and when behind-the-meter supply can energize 3.5 years sooner.

3 | Batteries and over-procurement erode the merchant revenue gas depends on, first in ERCOT and next in PJM. We see strong battery additions across markets for years to come, and that growth puts downward pressure on ancillary service and capacity prices for everyone, including gas. BESS growth in ERCOT has brought ancillary service revenue per kW of storage down from about $125 in 2023 to $8 in 2025. Meanwhile, elevated load forecasts risk over-procuring capacity. PJM’s backstop procurement targets about 15 GW where our load view supports about 6 GW, enough to cut capacity prices by up to 29%.

4 | Premium buyers rank speed to power ahead of low carbon today, so clean supply has to prove itself at scale to move up their list. Most of the low-carbon value chain depends on off-takers that value low-carbon attributes. Many of those are the same data center developers focused on speed to power near term, even if low carbon remains a longer-term priority. That can switch once technologies like geothermal prove their technical reliability. Fervo’s Cape Station is operating, and we are excited to see the data on sustained output, thermal drawdown and water loss.

5 | Coordination is the next bottleneck, rewarding developers who can bring labor, equipment, fuel and approvals together on schedule. I have heard some version of this repeatedly in recent weeks. Pipeline permit denials delayed the gas supply intended for Oracle’s Project Jupiter, where one missing approval exposed the wider investment to delivery risk. It is telling that businesses with capable, secured labor forces suddenly look like compelling acquisition targets when that labor derisks part of your execution. I expect construction capability and captive labor pools to become more valuable.

It all keeps coming back to one set of customers. Data centers are setting the economics of new dispatchable power, drawing the attention of regulators and policymakers, pushing up supply chain costs and holding the lifeline for low-carbon technology. We see a way to play in each theme for every segment of the industry, and we have the detail to help you find and derisk yours.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

EOR has a market for CO₂. Buying it at $30/t, our breakevens run $47/bbl to $51/bbl, and recycling more helps: going from a 50% to 70% recycle rate saves $4/bbl. Adding the $85/t 45Q credit reverses that calculation. CO₂ left in the reservoir turns from a cost into revenue, and the oil becomes a bonus. Our breakeven falls to $33/bbl at a 70% CO2 recycle rate and $14/bbl at 50%, amongst the cheapest oil we see on the continent. Integrated operators like Occidental and ExxonMobil are best placed to benefit.

Supplying that CO₂ is harder. Capture costs came in 77% above our prior estimate. The $85/t credit covers capture costs for 46% of U.S. capturable CO₂, but it must also pay for transport and storage. For a single source, 100 miles of pipe and a storage site add $20/t to $30/t, leaving $55/t to $65/t for capture. Even at $65/t, only a quarter looks economic. There is a reason natural gas processing and ethanol are leading CCUS growth this year.

Shared pipes and storage could bring those costs near $5/t each, putting $75/t capture sources within reach. CF Industries, ExxonMobil and Energy Transfer hold 39 Mt of the cheapest CO₂ across 34 sites, and are natural anchors for that kind of hub.

Power demand brings new candidate emissions as capacity expansion adds new gas-fired emitters. Amongst retrofit candidates, 478 of 638 combined-cycle units can support capture and earn a 10% return if they secure $100/MWh power purchase agreement (backed by a buyer paying for low-carbon power). But the analysis assumes baseload operation, and we expect gas capacity factors to fall through 2030. This might look better in the model than on the ground.

Cheaper energy will not help. Energy accounts for 9% to 39% of capture cost, so even a 90% cut in energy requirement lowers capture costs for gas plants by only 9% to 11%. Ironically, efficiency does not pay here. The newer H-class turbine costs more to capture from than F-class, $153/t versus $133/t, because its exhaust is more dilute and offers less usable heat.

The other end is niche. Direct air capture drew no venture funding in 1H26, and Microsoft accounts for 44% of carbon removal purchases. That is a long way from industry hype. I think the way back runs through shared pipes and storage, and that takes cooperation and aggregation at a scale we do not see yet. Until then, do not discount the niches where the right source, pipe and reservoir under one owner and you get oil at $14/bbl.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

The incentive to keep options open is substantial. Our study of 5,901 completed transmission upgrades puts the slow case, the 90th percentile, at 54 to 62 months from authorization to service across four markets. Applications and studies come before that clock starts. Waiting for certainty can be expensive.

Developers therefore apply earlier and pursue more opportunities. Equipment buyers reserve slots before the rest of a project is settled. Our turbine work separates GE Vernova’s 116 GW of gas turbine commitments into 53 GW of firm orders and 63 GW of reservations. Its firm share fell from roughly 54% to 46% over the year as new reservations outpaced conversions. These are meaningful commitments, but they sit at different stages of maturity. Scarcity begets proposals.

The challenge is translating those commitments into consumption. We track what data center developers are proposing and building alongside what utilities and independent power producers are preparing to supply. Project schedules, chip availability, capital spending and utilization determine how much becomes load, and when.

That work puts annual electricity demand growth in ERCOT at 3.9% through 2030, versus 15.1% in its published outlook. Adding back the demand we expect behind the meter still leaves us well below the grid operator. Last week’s explanation of onsite supply accounts for only part of the difference.

Utilities face a similar translation problem. Requests support investment proposals; regulators determine what earns a return. Our utility analysis puts WEC’s projected annual load growth at roughly 11%, against our forecast of 3.4%. Its valuation implies dividend growth of 2.8%. Load and dividends need not grow together, but across our utility coverage, aggressive load guidance does not consistently earn a higher growth premium. Requested megawatts still need a credible path to shareholder cash.

The harder power is to secure, the earlier customers must stake their claims. Reading those claims as consumption risks building the wrong forecast around rational behavior.

Our team heads to Yotta next week to compare notes with the people requesting power and those supplying it. Join us at our happy hour. I suspect demand for a drink will survive the move from reservation to consumption.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

For any new data center project, time-to-power is the first criterion. To have a project you need a timely pathway to a powered shell. Cost is rising on the grid-served path. Texas, for example, is rewriting transmission cost allocation for large loads by year-end, and BTM offers the fast lane around it.

The math explains why. On-site power carries a premium of roughly $15 to $35/MWh versus grid power delivered at $69/MWh. Our base case puts the 20-year present value of that premium at $1.58 million/MW. Energizing 2.5 years earlier is worth $3.1 million/MW. About 15 months of earlier operation covers the premium.

ERCOT takes a median 32.7 months to build the transmission upgrades triggered by a large load, after studies and approvals. Reciprocating engines and fuel cells can deliver power in 18 to 24 months from order. That gap pulls projects behind the meter.

Once the path to first power is established, developers optimize the economics. If you are building over multiple phases, as many large campuses do, that includes optimizing your relationship with the grid. Later phases have time for transmission studies, network upgrades and for tariff structures to stabilize.

That last point is growing in importance: tariffs are moving in one direction. Dominion’s GS-5 rate charges large loads for 85% of contracted transmission and distribution capacity and 60% of generation, used or not. PJM denies netting treatment to loads above 50 MW and charges them on actual grid reliance. Both charge you for the size of the connection rather than the use of it. That turns the connection from cheap insurance into a subscription, and it forces a real decision about how big to make it. Contract large and the capacity cost is sunk, at which point grid energy beats on-site fuel at the margin and the plant built for phase one drifts toward backup.

This complicates the load growth picture. We have long held that queues overstate total demand. Now policy is pushing more near-term projects behind the meter, so even the real demand shows up off-grid more often than most forecasts assume. That is not the end state. As those projects mature, we expect even the fully islanded ones to build toward the grid. Longer transmission delays are the risk, since they turn the phase-one plant into the permanent plant.

So when you hear BTM, do not stop at the label. Ask how thick the grid connection will be, and when.

Thoughts, questions or things we missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

Power is a challenge, but silicon is where we see the system binding today. Advanced packaging is booked through mid-2026. NVDA has roughly 60% of global CoWoS (the packaging step that stacks logic and memory) capacity for 2026 and 2027. All three HBM (high-bandwidth memory) suppliers have sold their 2026 allocation. In a truly power-constrained world, I would expect to see stranded GPUs sitting in warehouses. I have not.

Old chips are also living longer. If power were the binding constraint, and new chips delivered materially better tokens per watt, older GPUs should be retired faster or repriced lower. Instead, they are being recontracted above original rates, and that is happening even as per-chip draw goes 6x, from 300 watts in 2017 to an estimated 1,800 by 2027. That is not the behaviour of a market drowning in silicon and starved only for electrons.

The power story is more complicated. Large-frame gas turbine order books are full, but bridge capacity is available in fuel cells, reciprocating engines and aeroderivatives. Those categories can produce roughly 25 GW/year, against about 7.5 GW/year of data center additions. Order a heavy-duty turbine from GEV today and it arrives in 2031. That does not make power easy. It does mean the bottleneck is narrower than “generation.” The hard part is deliverable, permitted, AI-ready power at the right site by the right date.

Land tells the same story. Hyperscalers control about 54,000 buildable acres, less than 40% developed. Raw land is plentiful. Useful land is scarce. Our powered-land ladder climbs from $75,000/acre raw to $1.67 million/acre energized, and only 5% of parcels entering entitlement get there. That explains the land banks. It also explains the bloated load queues.

Which brings us back to The Goal. Relieve one bottleneck and another appears. Silicon should ease as manufacturing capacity expands. But delivering power, conditioning it for AI loads and putting it into shells built to use it is getting harder.

Start with the economics. Large-frame capex has moved from $0.9 million/MW in 2023 toward $2.4 million/MW by 2027. A large-frame combined cycle can take up to 80 months to reach commercial operation. Recips and fuel cells are faster, often 18 to 24 months, but faster is not the same as frictionless. They still need permits, fuel, interconnection, emissions approvals and a customer willing to pay for speed.

The politics add another drag. Batch Zero rationed access. The price was $50,000/MW, with 80% forfeited if the customer walked. Expensive, but at least it came with rules and a timeline. Governor Abbott’s moratorium and queue audit may change few outcomes while burning months. That delay could matter more than the money. Tariff reform and cost allocation will add more friction. The case for private-use networks gets stronger with every month lost in the queue.

In a system growing this quickly, no constraint stays binding for long. Chips bind today. The edge is spotting the handoff before it is obvious, because obvious constraints get priced. Goldratt’s plant manager did not find one permanent machine. He learned to watch where the line backed up.

Thoughts, questions or things we missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

Power markets are adjusting too. Megawatt-hours still matter, but their value increasingly depends on shape: hour, season and location.

Start with the day. Over the past twelve months, Texas hub power averaged $34/MWh at 8 am, fell to $18 at 11 am and climbed to $57 by 8 pm. Two peaks now, and the cheapest hours have moved from the middle of the night to midday. Power at 4 am clears $28, more than half again the $18 midday low. That is what happens when utility-scale solar generation grows sixfold in five years.

The calendar shape is also changing. Heating electrification is pushing parts of the Northeast toward winter peaks, and the crossover starts now, not in the distant future. NYISO’s North zone is already winter-peaking. Maine follows in 2028 and AEP in 2032. And winter has no midday solar surplus to lean on.

Patterns are shifting across geography. In 2023, West Texas solar captured 71% of its local average price while the rest of ERCOT sat near par. This year capture has fallen to 56% in North Texas and 59% in Houston. The panels spread east, and the cannibalization followed them. Building somewhere else is no longer much of a strategy.

Storage has been both victim and beneficiary. In March, Battery Brawl showed average ERCOT battery revenue collapsing from $149/kW in 2023 to under $20/kW in 2025. What remains rewards trading and dispatch. Batteries now set the marginal price 23% of the time, at an average $56/MWh against $35 when combined-cycle gas is marginal.

New dispatchable capacity faces the other side of the same problem. ERCOT does not have a capacity market, so a plant recovers its costs from energy and ancillary services. Construction runs $2,000 to $3,000/kW, and our work puts the PPA floor for a $2,500/kW combined cycle near $70/MWh, against hub power averaging roughly $32. That floor assumes the plant runs 75% of the time, which is exactly what a shifting curve takes away. A peaker can pick its hours, but it has far fewer of them to spread the same cost over. Of about 60 GW of ERCOT gas in development, only 6 GW clears our readiness screen, and none of it gets built without a contract.

Shape, not volume, is now the main variable in power asset value. And the shape underwritten three years ago is already gone.

Thoughts, questions or things we missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

Energy technologies can look goofy, even laughably primitive, for much of their lives. Then one day they aren’t. Wind and utility-scale solar went from less than 1% of U.S. generation in 2005 to 17% in 2025. Fusion may eventually do the same.

Yes, the same fusion that gets snickers from the crowd. Private fusion companies report $15.2 billion of cumulative funding, so somebody believes. And 42% of developers surveyed by the Fusion Industry Association expect the first commercial fusion plant to deliver electricity by 2035. Comically soon for a technology seventy years in the works. After watching the robots cut 57% off the winning time in a year, and seeing AI speed up work across the sciences, I am less inclined to snicker.

The robots race again next year. Fusion gets one run a decade. Even taking developers at their word, the 4 GW to 6.5 GW disclosed by U.S. companies is small beside the 79 GW of grid-served data center load we expect by 2035. Fusion may eventually stop being funny, but not in time to carry this build cycle.

Existing fission is already doing useful work. Our nuclear power purchase agreement screen identifies roughly 2.1 GW of uprate potential across 14 plants, including 340 MW at Limerick. No new site or reactor required. META’s Vistra agreement supports 2,176 MW of operating generation and another 433 MW of uprates in the early 2030s.

Across six independent power producer nuclear deals, we estimate an average first-year price of $86/MWh, a $34/MWh premium to zonal forwards. AMZN’s premium over merchant power rose 73% between Susquehanna and Comanche Peak. Buyers are paying for time.

Our IREN work explains why. Initial build costs run from $31 million to $50 million/MW, and at full build we model about $9 million/MW of annual revenue at an 83% EBITDA margin. At a 95% capacity factor, twenty years at that nuclear premium costs about $5.7 million/MW before escalation. One year of modeled EBITDA is worth more.

Holtec Nuclear’s planned IPO brings both bets together: an operating nuclear-services business and the Palisades restart, alongside the SMR-300. The market will decide how much to pay for useful work and how much for the possibility that one day the robot stops looking goofy.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

If you are going new, CCGT costs cluster near $2,000/kW for the post-2027 cohort against roughly $900/kW before 2023. In ERCOT a 1 GW plant at a 6.5 heat rate and 75% utilization cannot be financed above $1,500/kW on conventional terms, so it takes a PPA near $70/MWh to break ground. PJM needs roughly $500/MW-day of capacity, or a 15-year bilateral at the cap. Numbers will vary, but the band is narrow and knowable.

The market to buy is hot. Operating gas M&A doubled from about $0.5 million/MW before 2025 to roughly $1.0 million/MW last year, and against a $2.0 to $2.3 million replacement cost that is fifty cents on the dollar. Expanding at an already-interconnected site lands at $1.3 to $1.6 million/MW. The cheapest megawatt in the market is one that already exists.

Long Ridge showed what that megawatt is worth. MARA’s purchase included the well pads as well as the operating asset and implies a $52/MWh contract. Priced off an $80/MWh behind-the-meter PPA instead, a $15/MWh uplift to LMP and in line with comparable deals, we value the Hannibal plant at $3.76 million/MW against $2.53 million merchant. Capturing the contract means a ~50% uplift for the same turbines, at the same node, burning the same gas.

Not every plant has the same options. When Talen paid $1.33 million/MW blended for three gas plants in January we marked Waterford at $2.22 million/MW and Darby at $0.34 million. Waterford earned that on merit, a 7.0 heat rate running 88% of the year, and the same efficiency is what makes it worth contracting. Darby runs 8% of the year on a 12.4 heat rate, so it is cheap today with no option to contract. Across the fleet, the plant with the best heat rate carries both the highest value per megawatt and the largest PPA upside, roughly 16% of NAV at $60/MWh.

Old or new, the upside sits in PPAs struck above merchant. I would pay for the plant and chase the option, which means the work is finding the plants that carry one. Pick the right heat rate at the right node. Get past a market monitor that already killed Talen’s Susquehanna colocation and wants Long Ridge’s capacity kept in PJM. Sign the contract. Or watch somebody else do it.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

Utility physics follows the same pattern. Load growth should predict earnings growth. Utilities are designed to serve load, after all. Growing demand means more generation, transmission and distribution, which should mean more rate base. Per-share growth should follow if the utility grows rate base, earns its allowed return and avoids diluting the equity along the way.

Easy math. And it works, up to a point.

In our Utility Compass, the relationship between our load forecasts and market-implied growth is positive, but the slope is shallow and the dispersion wide. Dividend yield is the big lever, more than I expected, explaining 62% of the variation in forward price-to-earnings multiples across our coverage group. The remaining 38% contains differences in cost of equity and expected growth, and load should explain part of it.

Even if load growth has some explanatory power, the trajectory is noisy. AEP’s deck points to a 25.8% load CAGR through 2030, roughly 69 GW. We model 2.0% and 2.6 GW. The market implies 3.2%.

More broadly, our 2030 peak demand estimates run below disclosed guidance for every utility in the group. WEC is the only name where market-implied growth of 2.8% sits below our own estimate of 3.4%. ETR carries the widest growth premium in the group, roughly 4.1 points against our 0.4% load forecast.

Then there is the load that never arrives. We expect behind-the-meter generation to serve 41% of incremental data center load through 2030, roughly 30 GW of new gas capacity built outside the rate base. Of PJM’s 11.8 GW high-confidence large-load pipeline, 58% is expected to go behind the meter. MISO’s 11.6 GW stays 78% grid-connected, but its proposal would have those customers pay the attributed upgrade costs upfront. One market loses the load. The other keeps it and gives away the return.

Load growth is murky for utilities and investors alike. Converting it into earnings runs into a new limit: who funds and owns the build.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

ERCOT was playing its own summer games last week. The grid served a preliminary record of 91.1 GW on July 22, more than 5.5 GW above the previous official record. Breaching 90 GW is a big deal. How big? Up there with the Berlin Wall and the Apollo moon landing, at least according to our lead ERCOT analyst.

Load was also pulling a Mondo Duplantis, clearing the record without revealing how high it could really go. Summer in ERCOT is 4CP season. Under Four Coincident Peak, transmission costs are allocated based on demand during the highest 15-minute interval in each of the four summer months. Our team issued 4CP alerts ahead of the record, and some large users were likely responding by curtailing operations, discharging batteries or switching to on-site generation.

Did you notice? Likely not. ERCOT made history without the price spikes or public panic. Chalk that up as a win.

But what is good for customers today may not be good for them in the future. Record load produced a weak price signal for the firm capacity ERCOT may need under less favourable conditions. A few summer days clearing around $70/MWh will not finance much merchant capacity. We think new build needs a long-term contract at around that to pencil, not a handful of isolated summer clears.

While ERCOT was writing records, a transmission fault in Northern Virginia caused data centers to transfer more than 3 GW of demand to backup generation within seconds. For PJM, it was a generator outage in reverse: demand vanished, then returned once conditions normalized.

Large Load drops like this are a growing concern for grid operators. We expect 62 GW of new U.S. data center capacity through 2030. The risk of similar multi-gigawatt load swings is growing, and not just in Virginia.

ERCOT and PJM are telling the same story at different speeds. In Texas, cost-allocation incentives shape gigawatts of demand over hours. In Virginia, automated protection systems remove gigawatts of grid demand within seconds. Those lessons extrapolate across markets.

Grid operators have traditionally treated load as the score and generation as the players. Load is now on the field. It responds to incentives, anticipates the rules and occasionally makes its own moves. Like the games at our house, understanding what happens next requires knowing who is playing and which version of the rules applies.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

The change is evident in the ERCOT congestion data and our August Congestion Revenue Right (CRR) outlook. If power is not your day job, grid congestion is traffic for electrons, priced as the gap between points on the grid, and CRRs are how you participate in the market.

Our work ran six load and weather scenarios across the state. The wire into the Dallas Fort Worth hyperscale corridor and the line feeding Lancium’s Abilene datacenter bound in all six. Bottlenecks usually need weather, which is the point of running the scenarios. These bind on load alone, because real energized megawatts, Riot’s 400 MW, Lancium’s 500 MW, sit behind a wire that is already full. Data center load is making congestion structural.

Meeting that load also takes new generation. Our supply-side screen scored 95 in-development ERCOT gas plants, about 60 GW, on deliverability and offtake. Only 16 clear the bar into Tiers 1 to 3, roughly 6 GW. The other 54 GW sits in Tier 4, mostly at Facility Study with no contracted buyer, because a gas plant does not get financed until a creditworthy load signs the PPA. A $2,500/kW CCGT needs roughly $70/MWh to pencil, and merchant revenue in an energy-only market does not get there. The buyer signs first. Everyone else waits in the queue.

So who benefits? LCRA owns the top of the table, with both Schneider RICE phases the only names at 77.5% and its Schneider CCGT and Lost Pines Recip close behind. Deliverability does the sorting, not size. Among listed IPPs, NRG’s Cedar Bayou 5 screens highest at 58.4% on a signed interconnection agreement, while the other 5 GW of NRG gas sits in Tier 4 with no offtake. VST’s Texas Gulf Sulphur scores 54.1% and is all of 16 MW. Headline gigawatts are the cheapest thing in this market.

PJM is the same match on a bigger pitch. PJM East spends $3.5 billion a year on transmission, the most in the nation, and congestion still moves the wrong way. The clocks explain why. Load arrives in three years, generation takes four to six, transmission takes ten.

The grid is Messi at 39, living on the magic that’s left, still capable for producing frantic comebacks. But the load wave is only warming up. Beautiful football is patient. It waits for the magic to run out.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

Meta’s power arrangement is by now commonplace. The load gets matched with renewables on paper, annually, while the firming comes from the Greenlight Electricity Centre, a 932MW gas plant Pembina (with partners Morgan Stanley Infrastructure Partners and Kineticor Asset Management) is building against a long-term Meta tolling agreement, online by 2030. Clean on the surface, gas underneath.

Looking to the US data center build, the fuel cell is an interesting variation on the theme. Our work has Bloom’s solid oxide stacks penciling around $91/MWh behind the meter, within 1% of a combined-cycle plant, and Oracle stood one up in 55 days. The technology is attractive for the use case, and the stock has run roughly 1,000% in a year on that promise.

The real bet is the order book. Bloom looks reasonable as long as it executes on its backlog, and that is where the whole thesis sits. Some of it is signed and binding. Some is announced, optioned or aspirational. The gap between the headline and what Bloom ultimately installs is the difference between a scaling infrastructure platform and a product that is more hat than cattle. There is nothing new about this. Whether it is the Big E exploration or technology, the potential shows up in the order book and investors are asked to bet on its quality.

The pattern underneath holds either way. Getting to the groundbreaking ceremony is the hard part, and plenty of announced projects get bucked off in the queue and never energize. What keeps one on to eight seconds now is a signed buyer. Post-2024 combined-cycle plants cost around $2.0 million/MW to build while existing gas trades near $1.0 million/MW, so an acquirer pays 50 cents on the replacement-cost dollar. Nobody spends into that math on hope.

Williams proved it in the US yesterday. It pulled $5.34 billion from a Blackstone-led group, with Apollo and KKR, for 49% of its first five behind-the-meter gas projects, keeping control and pointing the capital at a backlog north of 6 GW. Pembina builds gas in Alberta against a Meta toll. Williams builds gas in the US against contracted demand and shared capital. Fuel cell or turbine, the rule holds. The buyer signs first.

Coming up: Join Pat Lynch of CBRE and me tomorrow as we discuss “Bringing the Site to the Power” and the realities of data center development.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

For larger projects, clearing the under-construction bar ahead of the deadline won the prize of “safe harbor”: roughly four more years to reach commercial operation and still collect the credit. Meet that bar, and the investment and production tax credits keep paying out well beyond 2027.

For small and residential systems that build in weeks, the end-2027 deadline is well within reach, so locking in under-construction status this summer mattered little. But for utility-scale projects, first queue date to an interconnection agreement alone runs three to four years, before a shovel moves. Without the time that safe harbor buys, the tax credits are effectively worthless.

That is why the fight over what “begin construction” means got contentious. For years a developer could lock eligibility on paper, spending 5% of project cost, no dirt required. IRS Notice 2025-42 tried to remove that route, leaving physical work as the only path. But on June 6 a federal court vacated the notice and restored the 5% safe harbor, and conceded its own appeal would not resolve before the deadline it was fighting over. At the project level, OBBBA’s impact is messy and uneven. Right after enactment we pegged 30% of queued solar and 57% of onshore wind as economic without credits at all. At EVOLVE in May we mapped some solar clearing below $30/MWh in MISO and PJM and the best Midwest wind under $20/MWh. Pine Gate’s bankruptcy was a reminder of the risk weaker portfolios still carry.

Zoom out and safe harbor looks more like a bridge than a loophole. Solar and wind are what most of the country can build now, and the under-construction wedge, 133.8 GW and rising, has roughly four years to come online, supported by tax credits and climbing PPAs. That capacity carries the system until gas turbine deliveries ramp and firm resources like SMRs and geothermal arrive at scale. The date everyone raced to beat turned out to be a starting gun, not a finish line. Four years to turn safe-harbored paper into steel, and to build a bridge to the next era.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

Power markets have their own brackets. Big announcements building queues everywhere. The hard part now is filtering the contenders from the pretenders. That is where our team is spending a lot of their time.

Start with data center capacity, the clearest read. About 96% of the additions we expect in 2028 trace to projects under construction or contracted. By 2030 that share falls to 26%. The bets you can place today fade fast a few years out. Potential is not the issue. We have mapped 272 GW of it in our Sites Unseen work. Naming the winners a couple years out is the murky part, and even marquee projects slip; OpenAI and Oracle scrapped a 600 MW expansion at their Abilene Stargate campus. Sorting that out is the game we are playing.

Emerging technologies and long project queues raise the same problem in sharper form. The market prices the prospect. We try to price the proof. That gap can be the whole valuation. O&G veterans have seen it before. OGX went public in 2008 as Brazil's hottest offering, claiming exploratory success north of 90% and reserves to rival the majors, then the wells came in dry and the stock lost 99% of its value. The resource was prospective. It was never proven. Price a story as if it is solved and you underwrite the promise. Price what has been demonstrated and you underwrite the well.

ERCOT decided to charge for the filter. Batch Zero asks 197 large-load projects to put up cash, $50,000 per MW, $50 million for a gigawatt campus with $40 million at risk if you walk. Announcements are free, but deposits are not. By our count 55 advance to the next round, 21.7 GW, and the rest wait for Batch 1+. Making the bracket does not guarantee the trophy, but you have to get in to have a chance.

The rules keep moving. FERC’s June orders to all six grid operators will reshape how large loads connect. Better stay on top of that.

Canada is through the group and a knockout round. It only gets harder. Power runs the same gauntlet, except the capital commits years before the whistle. Calling which side survives is the game.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

Start with location. Chevron (CVX) signed a 20-year deal to power a Microsoft data center in West Texas, building roughly 2.5 GW of dedicated gas generation on 2,000 acres in Reeves County, behind the meter and off the public ERCOT grid. On June 18 FERC pointed the rules the same way, issuing show-cause orders to all six grid operators and tilting toward colocated projects. The good address now sits next door to generation, and EIR puts AEP, Oncor and NEE in the best zip codes to capture it.

Then fuel. The Chevron plant burns gas from the company’s own Permian fields, a short hop from wellhead to turbine to server. Fervo (FRVO) is the other side of that coin, introducing geothermal as alternative fuel. We see it priced to perfection at $35.09 against an EIR fair value of $18.10 even after granting the technology works. Its rock is plenty hot. Converting that heat to steady megawatts is the hard part. The plan calls for about 25 power units a year, four times what the entire global ORC industry ships in a typical year, near 300 MW, or five to six units.

Then delivery, which is where the tenants separate. Chevron has already lined up the hardware, a majority of the generation from GE Vernova (GEV) turbines with the balance from Caterpillar’s (CAT) Solar Turbines, the exact equipment everyone else is waiting in line for. Crusoe is the counterexample. Black Hills confirmed it walked from Project Jade, a 1.8 GW campus in Cheyenne, leaving Black Hills to build directly with a customer that had already sunk more than $200 million into milestones. EIR’s ERCOT Batch Zero work scores all 197 large-load projects in the queue on exactly this, real tenant or tourist.

The grid has turned into a property market. Location, fuel, delivery. You get paid for the address, the megawatts and the ability to show up. The resource and the announcement are table stakes now. The deal closes for the one who shows up with the turbines.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

Taste will matter more when the machines can write. Judgment will be the moat.

I believe that is right. I also think most people mean something too soft by it. Taste is not a feel for clean prose or a nose for the elegant chart. Taste is the willingness to take a position and stand behind it long enough for someone to attack it. That is the thing that does not get cheaper. That is the thing organizations will pay more for, not less.

I have been building AI into my own workflow for months. Dictation changed the first mile, from thought to draft. AI-assisted editing changed the second. Together they shifted my production function. I can produce far more written work from the same amount of attention than I could a year ago.

So can everyone else.

If every analyst, strategist, PM, consultant, and executive can generate more drafts and more arguments, the world fills up with output. More memos, more dashboards, more plausible-looking arguments, more things that look finished because they are polished. It does not fill up with better decisions.

The constraint moves. Output bandwidth expanded. Input bandwidth did not. Reading still takes time. Absorbing an argument still takes attention. Deciding whether something is worth acting on still requires a person. AI widens the pipe coming out far faster than it widens the pipe going in, and that asymmetry is where the value relocates. What deserves attention. What should be done with it. Who is willing to sign their name to the recommendation.

This is where taste actually lives, and it is harder than the comfortable version.

A summary can be complete and leave everyone exactly where they started. A position points somewhere. It says, given what we know, do this. Or wait. Or this risk matters more than that one. Or this is the tradeoff we should accept.

That move is what makes analysis useful inside an organization. A position is specific enough to be challenged, grounded enough to be defended, and concrete enough that someone can disagree with it productively. A good position gives other people something to push back on. The pushback is the point. It surfaces the missing context, the hidden constraint, the better option, the place where the argument was weaker than it looked.

A lot of my year has been spent in rooms where positions get tested. Roadshows where the idea gets challenged and dinners where guests come at power and the energy transition from a different angles. AI helps me prep faster than I could have a year ago. It pulls background, surfaces prior positions, stitches together data I would have spent days gathering. That is the cheap part. What it cannot do is tell me which theme deserves to lead in each room. The same analysis lands differently with a long-duration investor than with someone running a trading book. The position I carry into a meeting is not the model’s output. It is what I am willing to defend, calibrated to who is across the table. The work product is not the deck. It is the set of positions that survive contact with people who have skin in the game.

The position I carry into a meeting is not the model’s output. It is what I am willing to defend, calibrated to who is across the table.

So what does taste actually decide? Three things have to attach to the analysis before it is worth anything. Judgment, context, accountability.

Judgment selects from the expanded possibility space. This is the part people point at when they say taste, and they are half right. Knowing when a sentence sounds good and says very little. Knowing when a model is precise around the wrong question. Knowing when a caveat is real and when it is throat-clearing.

Context shapes the surviving candidate into something that fits a specific room. Some of it is explicit: budget, operator, risk tolerance. Some of it is social: who got burned last cycle, which objection is real, which concern is performative, when the room is ready to hear the answer. AI can produce situated analysis if you hand it the situation. It cannot read the room.

Accountability is the part the soft version of taste leaves out, and the part that matters most. A recommendation can be handed off. A position has a person standing behind the reasoning long enough for it to be tested. That does not require certainty. It requires conviction strong enough to defend and humility honest enough to update. The sentence that matters is, “This is the best answer I can defend, given what we know and what we are trying to do.” AI can produce the reasoning behind it. Accountability still has to attach to a person.

If I am right about this, the analysts and firms that treat AI as an output multiplier are going to drown in their own polished noise. The ones that treat it as a position-generation system are the ones organizations will actually listen to. The work product is the quality of the positions someone is willing to defend, the speed at which they update them under pressure, and the track record of carrying them into rooms where decisions get made.

The work product is the quality of the positions someone is willing to defend, the speed at which they update them under pressure, and the track record of carrying them into rooms where decisions get made.

That is what taste is when output is free. Taste is the willingness to be wrong in public, on the record, with your name attached. The product is a position, because a position is the form analysis takes when it is ready to move.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Enhanced geothermal, Fervo and its peers, fractures hot rock and pulls heat fast by convection. The price is water lost to the formation. Closed loop, Eavor and XGS, seals the wellbore and loses very little. The price is a slow heat rate and higher upfront capital cost. Conventional hydrothermal, 17 GW worldwide, is the proven option, bound to the rare geology it needs. Superhot, Quaise and Mazama and 400 C, promises a step change in heat the engineering cannot yet deliver. Four bets, one pool of capital.

That isolation looks like a problem. Capital is finite, and a sector fighting itself for dollars fragments the story for every allocator trying to underwrite it. Fervo just priced a roughly $1.89 billion IPO at a $7.7 billion valuation. Eavor put 0.5 MW on a German grid in December, a quarter of its 2 MW first phase. Those are different risk profiles reaching for the same check.

But the cost of the tribalism is smaller than it seems. Below the surface the tribes stand on common ground. Fervo’s edge is multistage fracturing and fluid conformance lifted wholesale from the Permian, and SAGD operations in the Oil Sands. Eavor drilled Geretsried to 4.5 km with SLB. Quaise runs Nabors rigs and has raised $120 million. The conversion side leans on off-the-shelf hardware, ORC and flash steam, that predates all of them. The result? While the subsurface dialects diverge, the toolset is shared.

That shared toolset is why the fragmentation does not have to hurt. When a service company shaves a week off a lateral or drops cost per meter, every tribe benefits at once. Fervo cut drilling times 70% between its pilot and Cape Station. That learning curve does not respect tribal borders. It is one curve, and the whole sector rides it, whichever subsurface approach turns out to have the most velocity.

The hyperscalers already sense it. Meta signed 150 MW with Sage and another 150 MW with XGS. Google lined up both Fervo and Ormat through the same Nevada tariff. They are spreading chips across the tribes because the ground underneath is the same.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

If you build on frontier models, the question is no longer theoretical. How exposed are you to a switch you do not control?

The lesson is that rented frontier capability is revocable. Backup models help, but they do not solve the deeper problem. A model you do not own can be recalled, restricted, degraded, or made unavailable through a decision made above you. You may find out at the same time your users do.

That risk always existed in theory. This week it became an operating assumption.

The common read is that the newest model is always the prize. I think that is incomplete. The newest model is also the least understood model. It has the least operating history, the least mapped behavior, and the greatest regulatory surface area. For many commercial workflows, stepping back from the frontier gives up less capability than people assume while reducing exposure to the most switchable part of the stack.

For most companies, the edge was never only in the model. It is in proprietary data, domain judgment, workflow design, and evaluation. A near-frontier or open-weight model, paired with the right data and measured against the work that actually matters, can beat a generic frontier model on the jobs that pay you.

Keep using frontier models. Do not build the company around the assumption that one will always be available.

We have spent years talking about data sovereignty. Inference sovereignty is next. Controlling where your data sits is different from controlling the model that reasons over it. The expertise you layer into a model through tuning, memory, skills, prompts, evaluations, and workflow design becomes an asset you either own or rent.

The firms that demanded data privacy will increasingly demand inference sovereignty too: control over the model, the reasoning layer, and the institutional know-how embedded inside it.

The practical answer is architecture.

Keep model IDs behind an abstraction layer. Maintain fallback paths across frontier, near-frontier, and open-weight models. Move memory, skills, evaluations, and routing logic outside any single provider. Treat frontier access like an interruptible input: useful, powerful, and not fully under your control.

For energy, the bigger implication is fragmentation.

If more firms decide they need inference sovereignty, they will not all build hyperscale campuses. They will want controlled inference capacity closer to their data, operations, customers, or regulatory boundary. Some will sit in smaller data centres. Some will sit behind the meter. Some will be embedded inside industrial sites, campuses, labs, hospitals, banks, utilities, and defence-adjacent facilities.

The aggregate load may stay the same or rise.

Hyperscale compute is efficient because it pools demand, runs infrastructure hard, optimizes cooling, and shares capacity across many users. Sovereign inference moves in the other direction. It favours control over utilization, proximity over scale, redundancy over sharing, and permission over pure cost minimization.

That sacrifices system efficiency for control. For firms worried that a provider, regulator, or government can interrupt access to their inference layer, the trade may be rational.

For grids, this makes AI demand harder to see and harder to plan around. Large interconnection requests will still matter, but more compute may appear as smaller clusters embedded inside commercial, industrial, institutional, and behind-the-meter load. The forecast becomes less about known hyperscale campuses and more about a sovereignty premium: lower utilization, more redundancy, and more distributed compute.

Inference sovereignty does not stop at the model. It extends through the chip, the site, the interconnection, and the meter. If the goal is control, compute and power become part of the same stack.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

What’s driving the move? Time to connect, growing pressure to cover most or all of the connection costs. It’s a bit like cutting the cord with cable. At first it looked easier, and cheaper. But over time our family found ourselves “needing” Netflix, Prime (free delivery), Disney+ (kids), and even a cable (sports)… a stack of streaming logins that keep us connected to new partners and, still, the cable company.

The data center industry is living the same experience with power. The promise of BTM is simple. Bring your own power, and you can skip the queue, run more DC supply (and capture the 13% gains from NVIDIA’s MW block), and maybe save money. Some will end up truly islanded, self insuring their reliability. But many will keep a tie to the grid. It just will not be for the full load.

The logic is simple. Sizing the wire for full peak means demand charges on the whole load, a network build, and years in the queue. The on-site fleet carries the bulk energy and the rack battery covers the fast swings. The grid tie becomes the expensive insurance layer: useful for startup, maintenance, partial import, future resource integration, or curtailed-load backup, but not necessarily sized to carry the whole campus. So you self-supply the cheap part and rent the expensive part on a thin tie, sized well below peak. The wire size decouples from the operating size. That is the whole trick.

The real deals already look like this. Tallgrass is building its Cheyenne Power Hub to bring its own power to Crusoe’s Project Jade, up to 2.7 GW of dedicated on-site gas on its own pipeline. That is about as close to off-grid as a project gets, and it still designed a grid interconnection into the plan.

This is why FERC and ERCOT are not writing rules for islands. They are writing menus, from PJM’s Non-Firm Contract Demand tier to ERCOT’s controllable-load and bring-your-own-generation elections. The grid is learning to sell a partial connection, and the data centers are learning to buy one.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.

For powered compute the builders are assembling fast. SoftBank, DigitalBridge, and ArcLight are stacking demand, digital infrastructure, and power under one $150 billion-plus roof. Blackstone put $5 billion into a TPU venture with Google. KKR and Energy Capital Partners staked $50 billion. Each looks like what a homebuilder sells: one counterparty that delivers the finished product, powered compute, and manages the trades that go into it. xAI already sells it, with Anthropic paying around $1.25 billion a month for all of Colossus 1, roughly 300 MW of powered compute.

But not every buyer is worth building for, and load is not one thing. For example, our electrification forecast adds about 24 GW by 2035 from heat pumps, EV charging, and industry, each with its own price elasticity and none in a hurry. Hyperscalers and model labs are different: large, concentrated, and creditworthy, and they care about far more than the commodity price: time-to-power, reliability, density, cooling, scale, execution certainty all factor. Microsoft is paying Constellation at least $100/MWh to restart Three Mile Island, double the market, for that bundle.

The timing is right. Sourcing powered compute keeps getting harder: more scale to coordinate, a grid clogged with big new loads, generation costs inflating, and local and regulatory pushback. Between the offtake and an energized megawatt sits a chain of sub-scale counterparties, the powered-shell developer, the IPP, the turbine slot, the chip schedule, each handoff a seam where the timeline can tear. The buyer is bankable. The middle is the problem. The platform is the alternative, collapsing the chain into one balance sheet.

Integrated, de-risked cash flows carry a far lower cost of capital than a chain of weak bilaterals could. Scale procurement and fewer coordination failures pile on. The customer’s total cost can fall even as the platform earns a strong return. That is also why the gas gets built. A merchant plant at $2,000 to $3,000/kW cannot clear against a capacity cap of $333.44/MW-day, well short of the ~$500 it needs, but a sponsor holding the hyperscaler’s contract underwrites it off-grid.

This is business model innovation. The margin lives in the cost of capital. Whoever owns the fewest seams and the deepest balance sheet wins.

Comments, questions or things I missed? Send me a note (or hit reply) - I would love to hear from you. Thanks for reading!

Morning Energy is a syndicated note published through Enverus Intelligence. My contributions will also be distributed here. Please note that links frequently lead to content available only to subscribers of Enverus solutions. Please reach out if you have any questions. Thanks! - Ian.