US Energy Policy: The IRA, Permitting Reform, and LNG Export Expansion

Introduction

US energy policy is one of the most dynamic and consequential variables affecting energy investment banking deal flow. Three interconnected policy areas, the Inflation Reduction Act and the 2025 law that cut it back, federal permitting reform for energy infrastructure, and LNG export authorization, decide which energy investments get financed, which projects get built, and where advisory mandates come from. Energy bankers advising on renewable energy, LNG infrastructure, power generation, and midstream transactions need to know where each lever stands.

The Inflation Reduction Act of 2022 created approximately $369 billion in energy and climate incentives, representing the largest clean energy investment in US history. The core mechanisms are tax credits: the Investment Tax Credit (ITC) provides a 30% credit for qualifying energy property, while the Production Tax Credit (PTC) pays about $0.03 per kWh of electricity produced (the 2025 inflation-adjusted rate with prevailing wage and apprenticeship rules met). Bonus credits for domestic content (increasing the ITC by one-third) and energy communities reward US manufacturing and investment in regions affected by fossil fuel transitions.

Starting January 1, 2025, the IRA moved from technology-specific credits to technology-neutral clean electricity credits: the Clean Electricity Production Tax Credit (Section 45Y) and Clean Electricity Investment Tax Credit (Section 48E), which apply to any zero-emission generation technology, adding advanced nuclear, geothermal, and other emerging technologies alongside solar and wind.

Treasury also tightened the test for starting construction. IRS Notice 2025-42 (August 2025) removed the 5% safe harbor for wind and for solar above 1.5 MW, leaving only the physical work test for projects starting on or after September 2, 2025. A federal district court vacated the notice on June 6, 2026, and the government did not appeal by its August 5 deadline, as Clifford Chance's briefing on the vacatur explains, so both tests were available at the July 4 cutoff. How each project proved its start is now a core diligence item in any wind or solar portfolio sale.

Beginning of Construction

The tax test that fixes which credit rules apply to a clean energy project. A developer shows construction has begun either by starting physical work of a significant nature (such as excavating foundations or manufacturing custom components under a binding contract) or by incurring at least 5% of total project cost, then must make continuous progress toward completion. Under the OBBBA, this start date decides whether a wind or solar project keeps its credits.

The tax equity market, the primary mechanism for monetizing IRA credits, has adapted. The IRA's transferability provision (letting developers sell credits for cash rather than structure partnership flips) widened the pool of buyers beyond the large banks and insurers that dominate traditional tax equity, which particularly helped smaller developers.

For the oil and gas sector, the $85 per ton 45Q credit for geologic sequestration survived the OBBBA, which also extended that rate to carbon used in enhanced oil recovery for facilities placed in service after July 4, 2025, a boost for carbon capture (CCUS) projects with EOR outlets. The 45V hydrogen credit of up to $3 per kilogram fared worse: projects must now begin construction before January 1, 2028 instead of 2033, per K&L Gates' summary of the OBBBA credit changes. 45Q remains one of energy's most durable policy supports, while hydrogen has become a race to start building by the end of 2027.

Federal permitting has historically been the primary bottleneck for energy infrastructure development in the US. Pipeline projects, LNG terminals, transmission lines, and power plants routinely face 3-5 year permitting timelines under the National Environmental Policy Act (NEPA) review process, with some projects delayed by litigation for a decade or more. Regulators have moved quickly on what they can change by rule; Congress has moved far more slowly on what needs a statute.

On June 30, 2025, DOE and FERC revised their NEPA procedures to remove references to the rescinded White House Council on Environmental Quality (CEQ) regulations. FERC also waived and then, on October 7, 2025, repealed Order No. 871, the 2020 rule that barred construction while rehearing requests were pending, so pipelines and LNG terminals can again be authorized to build while challenges are heard.

FERC (Federal Energy Regulatory Commission)

The independent federal agency that regulates the interstate transmission of natural gas, oil, and electricity, and oversees the construction and operation of LNG import/export terminals, interstate natural gas pipelines, and hydroelectric projects. Laura Swett, named chairman in October 2025, has prioritized streamlining infrastructure approvals, including blanket authorizations for LNG facility work.

That agenda reached LNG terminals on October 15, 2026, when FERC proposed an LNG blanket authorization program, as LNG Prime reported: work that does not raise a plant's capacity could proceed automatically, while expansions and new trains, tanks, and berths would need 60 or 90 days' notice instead of case-by-case orders. If finalized, it would cut expansion time and cost for operators with multiple trains under development, such as Cheniere Energy, Venture Global, and Sempra.

Legislation is the slower track. The House passed the SPEED Act (H.R. 4776), a NEPA overhaul, 221-196 on December 18, 2025, but it stalled in the Senate, where it needs 60 votes and Democrats doubted the administration would treat wind and solar fairly. On September 30, 2026, a bipartisan group led by Senators Shelley Moore Capito and Sheldon Whitehouse released a White House-negotiated alternative with shorter review and litigation deadlines; ENR reports that its sponsors want votes in the post-midterm lame-duck session. Any Senate bill must still be reconciled with the House text.

For energy bankers, the regulatory changes matter now and the legislation later. Building during rehearing and pre-approved terminal work shorten development timelines and make infrastructure more financeable; statutory limits on litigation risk would do more, but cannot be underwritten until they pass. Midstream project finance, LNG advisory, and transmission infrastructure mandates all benefit.

LNG export expansion has become a central pillar of the administration's energy policy. In January 2025, it ended the Biden-era pause on export authorizations to non-Free Trade Agreement (non-FTA) countries; the most significant approval since was the October 2025 final order letting Venture Global's CP2 LNG export up to 1,446 billion cubic feet per year. The Unlocking Our Domestic LNG Potential Act (H.R. 1949), which would move export authority from DOE to FERC and deem every application in the public interest, passed the House 217-188 on November 20, 2025 and awaits the Senate; until then, DOE's public-interest review, and the litigation that can follow it, stays on every project's critical path.

The market has moved with policy. US LNG exports averaged 15.1 Bcf/d in 2025, and the EIA's October 2026 Short-Term Energy Outlook projects a record 17.6 Bcf/d for 2026. Golden Pass LNG, the QatarEnergy and ExxonMobil venture in Texas, shipped its first cargo on April 22, 2026, with two more trains due by mid-2027. Policy certainty supports final investment decisions (FIDs) and the long-term demand thesis for Henry Hub gas; the LNG market article tracks the build-out project by project.

CP2 Phase 2 opened a run of 2026 FIDs: Caturus followed on May 15 with the 9.5 mtpa Commonwealth LNG project and $9.75 billion of project financing, and Delfin Midstream on June 3 with a $5 billion FID for the first US floating LNG export vessel. Each FID sets off a cascade of mandates: project debt, sponsor equity, gas supply agreements, pipeline commitments, and construction contracts.

The geopolitical case strengthened sharply in 2026: the US-Israel-Iran war that began on February 28 largely closed the Strait of Hormuz, and Iranian strikes on Qatar's Ras Laffan complex forced QatarEnergy to declare force majeure on LNG deliveries (the Strait of Hormuz crisis article covers the shock). Washington's emergency response came on the oil side: on March 11 the US committed 172 million barrels from the Strategic Petroleum Reserve to the IEA's record 400 million barrel release. Long-term sale and purchase agreements (SPAs) with European and Asian utilities supply the contracted revenue behind project finance, so LNG policy drives mandates from upstream gas supply to liquefaction finance and offtake negotiations.