US ENERGY UPDATE | May 8, 2026 View this email in your browser

Entergy Raises Its Four-Year Capex Plan to $57 Billion After Locking In a 5-GW Meta Data Center Deal in Louisiana

Entergy’s first-quarter earnings call on April 29 was less a quarterly update than a capital strategy reset. The company lifted its 2026–2029 spending plan from $43 billion to $57 billion — a $14 billion jump in three months — driven by a data center agreement with Meta for a campus in Richland Parish, Louisiana that could eventually reach 5 GW of load. Executing that agreement means Entergy is seeking Louisiana Public Service Commission approval for seven new natural gas combined-cycle units totaling more than 5.2 GW, along with roughly 240 miles of new transmission and battery storage facilities. The $27 billion in the plan earmarked for new generation is the headline, but the demand side of the story is equally striking: weather-adjusted retail industrial sales climbed approximately 15% year-over-year in Q1, and Entergy disclosed a development pipeline of another 7 to 12 GW of potential data center customers across its four-state footprint in Arkansas, Louisiana, Mississippi, and Texas. The Meta deal itself is structured to produce approximately $2 billion in customer benefits over 20 years, with Meta contributing $140 million to energy efficiency programs and $60 million to Entergy’s Power to Care bill assistance fund. What Entergy is modeling — a vertically integrated utility using long-term hyperscaler contracts as the anchor for multi-GW generation procurement — is becoming the most legible path to new thermal build in the Southeast.

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MISO’s New Load Forecast Projects 35% Peak Demand Growth by 2035, Driven Almost Entirely by Data Centers

The Midcontinent Independent System Operator published its 2026 long-term load forecast this month, and the directional message is unmistakable: a regional grid that went a decade with effectively flat demand is now staring at a 35% surge in peak load over the next ten years. MISO projects peak demand climbing from 121 GW in 2025 to approximately 163 GW by 2035, with data centers accounting for the dominant share of the growth — expanding from 9.6 TWh of annual energy consumption today to 266 TWh by 2046 under the current trajectory. In the near term, MISO is tracking 8 to 14 GW of new data centers expected to come online in 2026 and 2027 alone, concentrated in the central region covering Illinois, Indiana, and Michigan where low-cost land and industrial incentives are pulling hyperscale campuses. MISO was clear-eyed about the uncertainty embedded in those numbers: limited visibility into hyperscaler build plans, no centralized project database, and the basic question of whether AI demand materializes at the pace currently being projected. What the forecast doesn’t hedge is the structural implication — a demand profile dominated by flat, high-load-factor industrial consumers is fundamentally different from the weather-driven residential curve MISO was built to serve, and resource adequacy frameworks designed around the old shape will need updating.

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NextDecade Is Running Rio Grande LNG Ahead of Schedule and Targeting a 2027 FID on Train 6

NextDecade’s Q1 investor update this week was a notable departure from the cautious milestones that usually define LNG construction progress reports. CEO Matt Schatzman reported that Trains 1 and 2 at Rio Grande LNG are approximately 67.8% complete, with early electric commissioning for Train 1 underway, and that the five-train facility is tracking ahead of guaranteed substantial completion dates across all trains. First gas into the terminal is expected in the second half of 2026, with first LNG from Train 1 in the first half of 2027. FERC approved a switch to 24/7 construction scheduling in early April at no incremental EPC cost. The expansion story may be more consequential than the construction update: NextDecade plans to file its formal FERC application for Train 6 before the end of Q2 and is targeting an FID in the second half of 2027, with a potential start of commercial operations as early as 2032. Schatzman said the contracting pipeline for Train 6 already exceeds the train’s full capacity — a direct result of the Iran conflict creating sustained demand for long-term US supply commitments from buyers who can no longer rely on Qatari volumes. The company separately filed a request with FERC this week to extend its construction and in-service deadline from November 2028 to November 2031, citing the legal delays that slowed the original FID timeline for Trains 4 and 5.

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ExxonMobil Q1: Golden Pass Train 2 on Track for Year-End Mechanical Completion, Train 3 in Q2 2027

Golden Pass LNG shipped its first cargo in late April, and ExxonMobil’s Q1 earnings call this week filled in the ramp timeline. CEO Darren Woods confirmed that Train 2 is expected to reach mechanical completion by year-end 2026, with Train 3 following in Q2 2027. When all three trains are fully operational, Golden Pass will add approximately 15% to US LNG export capacity relative to 2025 levels — Train 1 alone already boosted that figure by roughly 5%. With Qatari export volumes constrained by Iranian missile damage at Ras Laffan and no short-term restoration timeline, US Gulf Coast liquefaction capacity is operating in as commercially favorable an environment as the industry has seen. Woods also confirmed that ExxonMobil is working toward final investment decisions on LNG projects in Mozambique and Papua New Guinea, both targeted for later this year — a signal that the company views the post-Hormuz supply tightening as a structural opportunity extending well beyond the current conflict. All three Golden Pass trains together carry nameplate capacity of approximately 18.1 million metric tons per year.

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The First US Offshore LNG Terminal Is Working Its Way Through Environmental Review

MARAD released its draft environmental impact statement last month for the ST LNG Deepwater Port Development Project — a proposed facility that would become the first offshore LNG export terminal in US history. The project would be sited approximately 10.4 nautical miles offshore Matagorda, Texas in roughly 65 to 75 feet of water, designed to export up to 8.4 million metric tons per year of LNG across four phased liquefaction systems of 2.1 mtpa each. Feed gas would arrive from the Tres Palacios Natural Gas Storage and Trading Hub and the Williams Markham Gas Processing Plant via a new 5.5-mile, 30-inch lateral pipeline. MARAD and the US Coast Guard are jointly overseeing the licensing process under the Deepwater Port Act; a public comment period is open for 45 days following EPA publication of the notice, and a public meeting was held in Bay City, Texas today. The offshore model is genuinely different from the Gulf Coast industrial corridor terminals that define the current US LNG buildout — smaller site footprint, different community opposition dynamics, and a permitting pathway that routes through maritime rather than land-use regulations. If built, it adds meaningful export capacity without the air quality and community conflict issues that have increasingly shaped the onshore approval process. Whether that translates to a faster or slower path to an FID is still unclear.

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PJM’s June Capacity Auction Is Arriving Without the Price Guardrails That Have Kept Costs in Check

The next PJM base residual auction — covering the 2028/2029 delivery year — is scheduled for June 2026, and it will run without the price cap and floor that Pennsylvania Governor Josh Shapiro negotiated with FERC in early 2025. That collar held the previous two auctions to a maximum of $333.44/MW-day; Monitoring Analytics estimated that without it, the December 2025 auction would have cleared at approximately $530/MW-day, adding roughly $10 billion more to ratepayer bills. The underlying supply-demand picture that drove prices to those levels hasn’t improved materially: PJM’s most recent auction missed its 20% installed reserve margin target by 6,623 MW, and load forecasts continue to be revised upward as data center development accelerates. Multiple state governors have asked PJM to extend the collar mechanism; the PJM Board has not acted. What June produces will be the market’s first unconstrained price signal in this cycle and a real test of whether sustained high capacity prices are actually stimulating the new generation investment they’re designed to trigger — or whether interconnection backlogs, permitting timelines, and gas turbine lead times mean the supply response simply can’t arrive fast enough to matter.

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Palisades Is Approaching Fuel Load After Completing Primary System Passivation

Holtec International completed primary system passivation at the Palisades plant in Michigan in late March — the first time since the facility shut down in May 2022 that the reactor’s primary coolant system was brought back to normal operating temperature and pressure. The process chemically stabilizes internal metal surfaces against corrosion and is a required precondition for fuel loading. With passivation complete, crews have shifted to a final set of activities including fuel handling system upgrades, switchyard restoration, and completion of required surveillance testing. The 68 fuel assemblies delivered to the site in October 2025 remain in secure storage awaiting NRC clearance to be loaded into the reactor core — that step, once it happens, will put Palisades on the threshold of the first nuclear plant restart from decommissioning in US history. Holtec continues to target 2026 for commercial operations. The project has the support of the Trump administration, the State of Michigan, which committed $150 million in state funding, and a $1.52 billion DOE loan. What it’s still working through are a set of regulatory documentation issues — including a Q1 admission that the plant has unauthorized nozzle welds on control rod tube penetrations — that have required NRC exceptions and contributed to the sequence of timeline slippage over the past year.

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IRENA Puts Numbers on a Threshold the Industry Has Been Approaching for Years: Firm Renewables Are Cheaper Than New Gas

The International Renewable Energy Agency published a major new report today — its first dedicated analysis of “firm” levelized cost of electricity — measuring not just what it costs to generate power from solar or wind, but what it costs to deliver reliable, continuous electricity from co-located solar, wind, and battery storage systems. The headline finding is specific: in high-quality resource regions, firm solar-plus-storage now costs between $54 and $82 per MWh, while new gas-fired generation runs above $100 per MWh globally and new coal in China comes in at $70 to $85 per MWh. IRENA attributes the crossover to cost declines that have been steep and simultaneous — solar PV installed costs down 87% since 2010, onshore wind down 55%, and battery storage down 93%. The agency projects an additional 30% cost reduction in firm renewables by 2030 and roughly 40% by 2035, which would push the best-performing sites below $50 per MWh. The timing matters for a few reasons: US federal clean energy credits have been substantially curtailed by the OBBBA, making the self-sustaining economics of solar-plus-storage in high-resource markets more relevant than ever to developers who can no longer underwrite projects on the assumption of a full ITC or PTC. The report explicitly flags data centers and AI infrastructure as priority markets for firm renewable systems — which are increasingly what hyperscalers say they want, and increasingly what the math says they can afford.

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Gas Producers Are Cutting Output — and Henry Hub Is Finally Responding

US natural gas production has declined by approximately 2 Bcf/d over the past several weeks to a 12-week low of roughly 107.6 Bcf/d, as producers led by EQT respond to sub-$3 prices with the kind of output discipline that’s become standard practice when Henry Hub gets soft. The curtailments are working: front-month futures recovered to approximately $2.86/MMBtu this week, a four-week high. Storage is still running roughly 7% above seasonal norms — a holdover from a spring injection season that included a single 103 Bcf build in mid-April — but that surplus is narrowing. The structural context here is worth noting. LNG export demand remains the primary support mechanism beneath domestic prices: feedgas flows to US liquefaction terminals averaged approximately 18.9 Bcf/d in April, a near-record pace, before softening to around 17.4 Bcf/d in early May as seasonal maintenance at several terminals temporarily reduced capacity. The increasingly hard-wired relationship between Henry Hub and global LNG clearing prices — with ECA LNG Phase 1 now commissioning, Golden Pass ramping up Train 1, and Rio Grande LNG approaching first gas — means the domestic gas market is going to have less and less room to trade on its own fundamentals and more and more exposure to whatever is happening in Europe and Asia.

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The US energy sector is in the middle of a genuine structural transformation. Record electricity demand from AI and data centers, a construction boom in gas, nuclear, solar, and storage, active geopolitical disruption to global fuel markets, and a federal policy environment that’s reshaping investment incentives in real time. US Energy Update tracks the stories that matter most each week: what’s being built, what’s being fought over, what’s moving prices, and what it means for the economy and the people paying the bills.

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