Energy isn’t a niche beat. It’s the cost of getting to work, the price of groceries, the reliability of the grid running the AI systems reshaping every industry.
US Energy Update covers the week’s most consequential energy stories: generation, infrastructure, policy, markets, and geopolitics, with enough context to understand not just what happened, but why it matters and what comes next.
NextEra Energy Is Running Two of the Biggest Energy Plays in the Country at the Same Time
It has been a remarkable ten days for the Juno Beach, Florida-based power developer. On August 12, NextEra Energy announced it had executed definitive agreements with the US Department of Commerce and the Government of Japan to fund the development and operation of up to 10 gigawatts of natural gas-fired generation — 5.2 GW in Anderson County, Texas and 4.3 GW in southwestern Pennsylvania — unlocking the first $3.3 billion tranche of development capital. The projects are part of Japan’s $550 billion US investment commitment under the US-Japan trade agreement, with President Trump’s formal approval in March. The money will fund early development activities including down payments on long-lead equipment — turbines primarily — and selection of engineering, procurement, and construction contractors. NextEra CEO John Ketchum said the company’s “hub strategy,” built over the past 18 months, was designed specifically to capture what the company calls “bring your own generation” opportunities: pairing large-load customers with dedicated natural gas capacity so that the cost is borne by those customers rather than existing ratepayers. The company currently has more than 30 such hubs in various stages of development. Initial resources are expected online as early as the end of 2028, with full project completion targeted for 2032.
Simultaneously, the company is advancing its proposed $67 billion all-stock acquisition of Dominion Energy — announced May 18, with regulatory filings submitted to FERC, the NRC, and the utility commissions of Virginia, North Carolina, and South Carolina on July 15. That filing triggered Virginia’s statutory six-month review process. The combined entity would serve approximately 10 million homes and businesses across four states and become the nation’s largest regulated utility. Under the proposed terms, Dominion customers would receive $2.25 billion in shareholder-funded bill credits — $1.78 billion of that in Virginia — over two years, and the companies have committed that merger-related costs will not be passed to customers. Virginia Governor Abigail Spanberger intervened in the proceedings on August 6, saying publicly that the deal must demonstrably benefit Virginians, and consumer advocates in multiple states are calling for closer scrutiny of rate impacts. The deal is expected to close in the second half of 2027 if all regulatory approvals are received on schedule.
The EIA’s August Energy Outlook Keeps Revising the Hormuz Damage Upward — and Prices Are Responding
The Energy Information Administration’s August Short-Term Energy Outlook, released August 11, is a sobering document. The agency raised its estimate of Middle East shut-in crude oil production compared to its July forecast, citing continued severe constraints on Strait of Hormuz transits that it now assumes will persist through August before flows begin gradually increasing in September. The numbers behind that assumption are striking: the strait carried approximately 4.9 million barrels per day of crude oil and petroleum liquids in the second quarter of 2026, compared with 21.6 million barrels per day in the fourth quarter of 2025 before the conflict began — a reduction of roughly 77%. Shut-ins averaged an estimated 5.5 million barrels per day in July. Brent crude is forecast to average $85 per barrel in the third quarter before declining to $69 per barrel in 2027 as production recovers. The agency also embeds a residual disruption of approximately 600,000 barrels per day continuing through the end of next year even under its base-case normalization scenario. US commercial crude inventories have fallen below 300 million barrels — the lowest level in more than four decades — as domestic and international buyers have drawn on every available buffer. Markets are paying attention: as of today, oil is hitting a three-week high on fresh uncertainty about whether the Iran-Oman shipping framework, announced last week, will actually translate into restored tanker traffic. The EIA’s August STEO also revised US crude oil production upward to 13.83 million barrels per day for 2026 — a new record — as high prices pull incremental Permian barrels into service. The agency projects gasoline prices to remain elevated through the remainder of the year, declining gradually as Hormuz traffic recovers and Middle East producers come back online through early 2027.
US Natural Gas Production Is on Track to Set an All-Time Record in 2026
The EIA’s August STEO pegs US marketed natural gas production at 122.5 billion cubic feet per day for the full year — a new record that surpasses the prior high of 118.5 Bcf/d set in 2025. Production has been climbing steadily through the year, driven primarily by associated gas output from the Permian Basin, where the EIA projects roughly 29.2 Bcf/d in 2026 — approximately 6% higher than the prior year — alongside continued strength in Appalachian dry gas from EQT and its peers. Henry Hub is expected to average roughly $3.70 per MMBtu for 2026, up from $3.53 in 2025, as LNG export demand and rising power-sector gas burn offset the softening effect of record production. LNG feedgas flows averaged approximately 16.5 Bcf/d in the third quarter to date. Perhaps most consequentially for consumers heading into fall: the EIA simultaneously noted in an August 11 press release that the country is on track for its highest natural gas inventories in a decade entering winter — a buffer that should provide meaningful insulation against the kind of price spike that pushed Henry Hub to $7.72 per MMBtu in January. The structural story here is the same one that has been building for several years: the US natural gas market is transitioning from a system priced almost entirely on domestic supply and weather into one where LNG export demand increasingly sets the floor, and where record domestic production is the primary mechanism keeping consumer prices from fully reflecting what global buyers are willing to pay.
Targa and ExxonMobil Just Locked In a 20-Year Permian Midstream Partnership — and Three New Plants to Support It
On August 17, Targa Resources announced three new natural gas processing plants in the Permian Delaware Basin — named Wrangler, Ranger, and Ranger II — with combined capacity of approximately 825 million cubic feet per day, targeted for service in the first half of 2028. The announcement came alongside new long-term, fee-based midstream agreements with subsidiaries of ExxonMobil covering integrated gathering, processing, treating, NGL transportation, and fractionation services across both the Delaware and Midland basins through 2046, with NGL dedications running through the same period. Targa also announced Bull Run II, a new roughly 70-mile natural gas pipeline in the Permian Delaware that will carry production from the new plants to the Waha Hub, supported by take-or-pay commitments. The company updated its full-year 2026 net growth capital estimate to approximately $5.0 billion and disclosed it is evaluating up to five additional processing plants to handle expected longer-term production growth in the area. The ExxonMobil relationship is significant: Targa is essentially building a dedicated processing and transportation corridor around one of the most productive acreage positions in the Permian. For natural gas markets, the implication is additional Permian capacity that will enable continued production growth well into the late 2020s — precisely the infrastructure expansion that the LNG export buildout on the Gulf Coast is counting on to supply feed gas at scale.
Wind and Solar Generated 57% More Electricity Than Coal in the First Five Months of 2026
EIA data released in July — covering generation through May 31 — crossed a threshold that would have seemed unlikely just a few years ago: wind and solar combined produced 57% more electricity than US coal plants in the first five months of 2026, and 26% more than the country’s nuclear fleet over the same period. In May alone, utility-scale and small-scale solar generated approximately 47,147 gigawatt-hours — more than coal produced in any single month. Total renewable generation grew 10.1% year-over-year in the January through May period, with utility-scale solar up 21.6%, small-scale rooftop solar up 12.8%, hydropower up 10.8%, and wind up 4.8%. Coal generation fell 10.9%. Wind and solar together now account for more than 22% of total US electricity production, and the combination of all renewable sources — including hydro, biomass, and geothermal — reached 30% of total generation in the first quarter. A structural milestone also cleared quietly in April: utility-scale solar capacity surpassed wind capacity for the first time in US history, at roughly 160,208 MW versus 160,101 MW for wind. None of this is happening because federal clean energy policy is supportive — the One Big Beautiful Bill Act’s construction-start deadlines have introduced real uncertainty for new projects. The growth is the product of economics: solar and storage installations are now moving through permitting and interconnection on timelines that coal and gas plants cannot approach, and costs have declined enough that the assets pencil out even without full federal tax credit support in high-resource markets.
Utilities Have Already Filed $18.6 Billion in Rate Increase Requests This Year — and the Midterms Are Making It Political
Electric and gas utilities have filed approximately $18.6 billion in rate increase requests with state regulators through the first half of 2026, according to an industry tracking report, adding fresh intensity to what has become one of the most visible affordability debates ahead of the November midterm elections. US electricity prices have climbed nearly 6% over the past year — comfortably above overall inflation — and the combination of grid modernization capital, extreme weather hardening, renewable integration costs, and data center-driven load growth is producing a capital expenditure cycle that regulators and ratepayers are only beginning to absorb. Texas utility Oncor filed the largest single request, at $1.2 billion, tied directly to meeting growing power demand from oil and gas operations and data center customers. For consumers already absorbing elevated gasoline prices from the Hormuz disruption, higher electricity bills arrive at an uncomfortable political moment: both parties are looking for someone to blame, and utilities — which receive guaranteed returns on capital while passing fuel and infrastructure costs to customers — are an accessible target. The Trump administration’s recently signed Ratepayer Protection Pledge, in which seven major AI and cloud companies committed to covering the full cost of grid upgrades and new generation needed to serve their data centers without passing costs to existing ratepayers, is an early attempt to draw a line between hyperscaler-driven load growth and residential bills. How robustly that commitment is enforced — through tariff design, regulatory conditions on large-load agreements, and FERC oversight — will largely determine whether the current rate environment stabilizes or accelerates.