Current Energy Mix

The US energy sector is in the midst of a gradual, market-driven transition rather than a mandated one, shaped by rising renewable investment, technological cost declines, federal and state policy, and surging electricity demand from AI and data-centre growth. Fossil fuels still dominate the generation mix, but renewables have grown steadily over the past decade, led by solar, wind and battery storage.

Renewables accounted for roughly 26% of total US electricity generation in 2025, up from about 24% in 2024, second only to natural gas. That growth has accelerated into 2026: Energy Information Administration (EIA) Electric Power Monthly data through May 2026 shows renewables supplying 30.3% of US generation for the first five months of the year, up from 28.2% over the same period in 2025, with utility-scale solar generation up over 20% year on year and hydropower also posting double-digit growth. Wind and solar combined (including small-scale solar) accounted for roughly 22% of total generation during this period, and in April 2026 utility-scale solar capacity surpassed wind capacity for the first time. Dispatchable sources – gas, coal and nuclear – nonetheless still supplied around 70% of US generation through early 2026, underscoring how early-stage the transition remains despite renewables’ faster growth rate. The pace varies significantly by state, reflecting differences in resource availability, market structure and regulatory approach.

Policy Framework

The USA has no binding national renewable energy target or mandatory fossil fuel phase-out. Instead, the transition is driven by a patchwork of federal tax incentives, state renewable portfolio standards (RPS) and clean energy policies, layered onto continued private investment in generation, transmission and storage. This decentralised structure lets states set their own pace and priorities, so both the speed of deployment and the legal framework for project development continue to differ materially across jurisdictions.

Solar photovoltaic (PV) and onshore wind are the leading sources of new renewable electricity generation in the USA, with battery energy storage now integral to most new project developments. Offshore wind has a smaller but growing footprint, concentrated on the East Coast, though its build-out has slowed amid permitting and policy headwinds. Hydropower remains the largest renewable source by cumulative installed capacity, but sees little new development given limited untapped sites and lengthy relicensing processes. Geothermal and biomass play more targeted roles, concentrated in regions with suitable resources (geothermal in the West, biomass largely in the Southeast and Midwest); tidal power remains at a pilot stage, with no significant commercial deployment.

Beyond electricity generation, renewable natural gas (RNG), biogas and sustainable aviation fuel (SAF) are gaining traction, particularly in transport and industrial applications, supported by federal tax credits and state low-carbon fuel programmes. Clean hydrogen investment continues, though the sector has cooled somewhat following the rollback of federal hydrogen hub funding and tax credit uncertainty under the One Big Beautiful Bill Act (OBBBA). Long-duration energy storage is an emerging focus alongside lithium-ion battery storage, as developers look for solutions to multi-day or seasonal reliability needs.

Overall, the mix continues to shift towards solar, wind and storage as equipment costs fall and demand grows, particularly from data centres and AI-driven load growth, while more capital-intensive or nascent technologies such as hydrogen and long-duration storage remain earlier in their commercial development.

The USA remains one of the world’s largest renewable energy markets, with sustained investment in utility-scale generation, battery storage and transmission infrastructure. Activity over the past 12 months has stayed strong despite headwinds from legislative change, permitting and interconnection delays, supply chain constraints and tighter financing conditions.

The market has been shaped largely by the OBBBA and the Trump administration’s related changes to permitting, federal land leasing, procurement and tax-credit guidance for renewable projects. Courts have pushed back on several of these efforts, finding that a freeze on offshore wind permitting was unlawful and that the government had improperly stripped tax benefits from renewable projects.

In April 2026, a federal judge ordered the Department of the Interior and the Army Corps of Engineers to halt policies restricting solar and wind permitting on federal land while litigation continues, in a case brought by a coalition of clean energy trade associations. That injunction touched policies tied to more than 57 GW of delayed or at-risk wind, solar, hybrid and offshore capacity, underscoring how much of the pipeline had been affected.

The administration has appealed the RENEW Northeast ruling to the First Circuit, so the scope and durability of the injunction remain unresolved pending that decision, and related litigation over offshore lease cancellations and Defense Department permitting delays is ongoing.

Transaction activity has remained robust despite this uncertainty. NextEra Energy announced a USD67 billion all-stock acquisition of Dominion Energy, while a BlackRock Global Infrastructure Partners and EQT-led consortium agreed to take AES Corporation private in a USD49.6 billion deal tied in part to funding delivery of nearly 12 GW of contracted clean energy agreements with technology customers. On the corporate offtake side, Alphabet’s roughly USD4.75 billion acquisition of Intersect Power stood out as a signal of hyperscalers moving directly into renewable ownership rather than just power purchase agreements (PPAs). Investors have generally favoured projects with existing grid access and long-term offtake contracts over greenfield development, and battery storage has drawn particular interest, with dozens of BESS acquisitions closing across the Electric Reliability Council of Texas (ERCOT), PJM and the New York Independent System Operator (NYISO) in early 2026 alone.

This resilience owes much to surging electricity demand from AI and data-centre growth, and to solar’s continued edge as the fastest generation resource to permit and build.

Renewable energy in the USA is governed by a layered federal-state framework rather than a single dedicated statute. At the federal level, the Federal Power Act, the Public Utility Regulatory Policies Act (PURPA) and the Energy Policy Act govern wholesale electricity markets, interstate transmission and the regulatory authority of the Federal Energy Regulatory Commission (FERC), while renewable projects are also subject to generally applicable environmental statutes – principally the National Environmental Policy Act (NEPA), the Clean Air Act, the Clean Water Act and the Endangered Species Act – that apply regardless of technology. There is no separate, standalone federal renewable energy code; renewable-specific rules instead sit primarily in the tax code and in agency permitting practice.

Authority is split along familiar lines: federal agencies regulate interstate transmission, wholesale markets, and activity on federal lands and waters, while states control utility regulation, resource planning, siting and retail markets. Many states layer on RPS or clean energy standards; others rely on utility resource planning or market mechanisms alone. This means the applicable legal regime for any given project depends heavily on its location and technology.

The dominant recent driver of change has been tax policy. The OBBBA accelerated the phase-out of the Section 45Y production tax credit (PTC) and Section 48E investment tax credit (ITC), the technology-neutral credits that replaced the legacy PTC/ITC under the Inflation Reduction Act (IRA), for wind and solar specifically, while other technologies (storage, geothermal, etc) retain a later phase-out beginning in 2034.

Wind and solar projects that began construction by 5 July 2026 preserved the ability to rely on the standard placed-in-service timeline (subject to the usual four-year continuity safe harbour); projects that did not begin construction by that date must now be placed in service by the end of 2027 to retain eligibility for the credits. The OBBBA also extended new foreign entity of concern (FEOC) restrictions to six credits that previously had none, barring “foreign-influenced entities” from claiming credits and raising domestic content thresholds for the bonus adder to 45% in 2025, 50% in 2026 and 55% thereafter.

A subsequent executive order directed Treasury to strictly enforce the 45Y/48E termination for wind and solar and tighten “beginning of construction” guidance, which Treasury implemented via Notice 2025-42, narrowing eligible methods for establishing a construction start date and effectively limiting most wind and solar projects to the physical work test. On 6 June 2026, the US District Court for the District of Columbia vacated Notice 2025-42 in its entirety, holding that the Internal Revenue Service (IRS) had acted arbitrarily and capriciously in imposing stricter rules on wind and solar alone under a technology-neutral statute, and the decision applies to all taxpayers, not just the plaintiffs.

That ruling restored the ability to establish beginning of construction under the prior, longstanding guidance (including the objective 5% safe harbour) rather than the physical work test alone. The government may appeal, and projects that relied on the restored safe harbour in the window before the July 2026 deadline may carry some residual eligibility risk pending further developments, but for now developers have regained a more flexible and well-established path to locking in eligibility ahead of the statutory deadline.

IRA-era credits for other technologies – storage, hydrogen (45V), carbon capture (45Q) and advanced manufacturing (45X) – remain in place, but now carry the new FEOC restrictions and, in most cases, an earlier phase-out than originally enacted.

Beyond tax policy, current activity centres on transmission planning reforms, interconnection queue modernisation and continued disputes (discussed elsewhere in this submission) over federal permitting priorities for wind and solar on federal land. States are separately advancing their own permitting streamlining and grid modernisation measures, so the pace and shape of near-term regulatory change continues to vary considerably by jurisdiction.

Regulatory authority over US renewable energy projects is split across federal, state and local bodies, with the applicable regulators depending on the project’s technology, location and stage of development. Developers typically engage several agencies in parallel across permitting, construction and operation.

At the federal level:

• FERC regulates interstate transmission, wholesale electricity markets and reliability standards, enforced through the North American Electric Reliability Corporation (NERC) under FERC oversight;
• the Department of Energy (DOE) administers funding, loan and research programmes but has limited direct regulatory authority over private projects; and
• the Environmental Protection Agency (EPA) enforces federal environmental statutes such as the Clean Air Act and Clean Water Act.

Projects on federal land or waters, or affecting federal waterways, require additional approvals from the Bureau of Land Management (BLM), the Bureau of Ocean Energy Management (BOEM) or the US Army Corps of Engineers, each with jurisdiction tied to the specific federal resource involved.

At the state level, public utility commissions (PUCs) regulate retail electricity rates, utility resource planning, interconnection and, in many states, the certification process for new generating facilities. State and local governments separately handle land use, zoning, building permits and state-level environmental review.

These regulators’ enforcement powers are broad and overlapping. FERC can compel information production, audit regulated entities and issue civil penalties for violations of the Federal Power Act or reliability standards – a statutory maximum of USD1 million per violation per day, adjusted periodically for inflation (currently frozen at 2025 levels following the lapse in required Consumer Price Index (CPI) data) – in addition to revoking market-based rate authority. The EPA has inspection, subpoena and administrative order authority, and can pursue civil or, in serious cases, criminal enforcement for environmental violations.

State PUCs typically hold authority to inspect utility operations, issue binding orders and impose fines or revoke certifications for non-compliant projects; BLM and BOEM can suspend or terminate federal leases for breach of lease terms. Because these powers operate independently and in parallel, a single compliance failure can trigger exposure across multiple regulators simultaneously, making co-ordinated compliance planning across the full regulatory stack a practical necessity for developers.

Renewable energy projects are regulated across their full life cycle, ranging from site selection, environmental review, permitting, interconnection, construction, generation, transmission and operation to decommissioning, but which rules apply, and at what level of government, depends heavily on technology and location.

Site selection and permitting differ most sharply by technology. Onshore wind and utility-scale solar sited on private land are primarily subject to:

• state and local siting authority;
• county or municipal zoning;
• setback requirements; and
• in some states, a state-level facility siting board with authority to override local vetoes.

Projects on federal land instead go through the BLM’s right-of-way process, including NEPA review. Offshore wind requires a lease and construction/operations plan approval from BOEM, plus consultation under the Marine Mammal Protection Act and Endangered Species Act given its ocean footprint, making its federal permitting burden considerably heavier than onshore projects.

Hydropower is the most distinctly regulated: new and existing dam-based projects require a FERC licence under the Federal Power Act, with a multi-year relicensing process for existing facilities that has no real equivalent in wind or solar. Geothermal projects on federal land require a separate BLM leasing process specific to geothermal resources; biomass and biogas facilities are regulated more like conventional industrial facilities, with air permitting under the Clean Air Act often the dominant constraint.

Environmental review applies across all technologies via NEPA (for federal approvals or federal land) and state-equivalent statutes – eg, the California Environmental Quality Act (CEQA) in California – but the intensity varies: offshore wind and large hydropower typically trigger full environmental impact statements, while smaller solar and onshore wind projects may qualify for more limited environmental assessments or categorical exclusions.

Interconnection requirements are technology-neutral in principle and are governed by FERC-jurisdictional generator interconnection procedures for projects connecting to the transmission grid, or state/utility-specific rules for smaller distribution-connected projects. Wind, solar and storage in practice dominate current interconnection queues, and reforms are underway across most regions to accelerate what has become a multi-year bottleneck.

Construction and operation obligations include Clean Water Act permits for stormwater and wetlands impacts (common to solar and wind construction), Federal Aviation Administration (FAA) obstruction clearance for wind turbines, and, for hydropower, ongoing dam safety inspection and compliance under FERC’s Part 12 programme. Battery storage is subject to fire code and safety standards (eg, NFPA 855) that have no direct analogue in generation-only technologies.

Decommissioning requirements are the least uniform: several states now mandate decommissioning plans and financial assurance (bonding) for wind and solar as a condition of permitting, an obligation increasingly extended to storage facilities, while decommissioning of a licensed hydropower facility is governed by FERC’s licence surrender process.

Utility-scale solar, wind, storage, transmission and offshore projects generally require the broadest set of federal, state and local approvals; smaller distributed generation (eg, rooftop or community solar) benefits from streamlined interconnection tariffs and, in many states, simplified permitting processes designed specifically to reduce the burden on smaller systems.

Private ownership of renewable energy assets in the USA is generally unrestricted. Projects may be owned by utilities, independent power producers (IPPs), private equity and infrastructure funds, pension funds or other investors, with no cap on foreign ownership as a general matter. That said, several specific restrictions and approval requirements apply to ownership and transfers.

Foreign Investment Review

Acquisitions by foreign persons are subject to review by the Committee on Foreign Investment in the United States (CFIUS), particularly for projects near military installations or other sensitive sites, or involving critical infrastructure; CFIUS can require mitigation measures or, in rare cases, block a transaction on national security grounds.

Tax Credit-Linked Ownership Restrictions

The OBBBA introduced new restrictions tied specifically to tax credit eligibility rather than ownership as such: projects owned or controlled by “specified foreign entities” or “foreign-influenced entities” (broadly, entities tied to China, Russia, Iran or North Korea) are ineligible for the Section 45Y/48E and related credits, and a change of control to such an entity within a defined period after placement in service can trigger the recapture of credits already claimed. This does not bar the underlying ownership transfer, but it materially affects deal structuring and buyer eligibility where tax credits are part of the value.

Regulatory Approval for Transfers

Transfers of “jurisdictional” facilities – generally those selling at wholesale or interconnected to the transmission grid – often require prior FERC approval under Section 203 of the Federal Power Act if the transaction involves a change in control of FERC-jurisdictional assets above applicable thresholds. Many states separately require PUC approval for transfers involving a regulated utility or, in some states, any transfer of a generating facility above a certain size. Hydropower is a further exception: FERC licences are non-transferable without prior Commission approval of the assignment.

Deal Diligence

Beyond these regulatory approvals, transfers are governed by ordinary contractual mechanics – purchase agreements, financing documents and consents – with buyers typically focused on project permits and approvals, interconnection rights, land ownership and lease agreements, PPAs and other material project contracts, plus confirmation that none of the foregoing regulatory approvals or tax credit restrictions are triggered by the change in ownership.

The USA does not restrict foreign investment in renewable energy generally, and foreign entities may own, develop, finance and operate renewable energy projects on the same basis as US persons in most respects. That said, several targeted restrictions and access barriers apply.

National Security Review

As with any US asset acquisition, foreign investment in energy infrastructure is subject to CFIUS review, which can result in mitigation conditions or, rarely, a blocked transaction, which are most relevant for projects near military sites, ports or other sensitive locations, or involving critical infrastructure or certain data/technology components (eg, some battery storage or grid software).

Tax Credit Eligibility Restrictions

The OBBBA’s FEOC rules do not bar foreign investment as such, but disqualify projects owned, controlled or materially assisted by “specified foreign entities” or “foreign-influenced entities” (entities tied to China, Russia, Iran or North Korea) from claiming Section 45Y/48E and related credits, and impose domestic content thresholds for bonus credits. This has a substantial practical effect on market access for Chinese-linked manufacturers and investors in particular, even though it operates through the tax code rather than direct ownership restrictions.

Trade Remedies on Equipment

Foreign-manufactured solar panels, cells and certain wind and battery components are subject to a patchwork of tariffs and trade remedies, including anti-dumping and countervailing duties on solar cells and modules from China and, following circumvention investigations, from certain Southeast Asian countries.

The broader tariff landscape has shifted repeatedly and remains highly fluid: the original Section 201 safeguard tariffs on imported solar cells and modules expired in February 2026 after eight years in place, but Section 301 tariffs on Chinese solar panels (currently around 50%) remain in effect, and the Trump administration’s sweeping International Emergency Economic Powers Act (IEEPA)-based “reciprocal” tariffs were struck down by the Supreme Court in early 2026 before being partly replaced by a new statutory tariff mechanism.

Given how frequently these measures have changed since 2025, project developers and equipment buyers need to treat the tariff picture as a live, moving target rather than a settled cost input, and should confirm current rates at the time of procurement. These measures affect equipment sourcing and project economics rather than investment or ownership directly, but they meaningfully shape which foreign manufacturers can supply the US market competitively.

Market Participation Requirements

Foreign-owned generators seeking to sell at wholesale must obtain FERC market-based rate authority (or sell under cost-based rates), the same requirement that applies to domestic sellers; FERC’s market power screens apply equally regardless of ownership. Foreign ownership of transmission assets or utilities can also trigger additional state PUC review in some states, separate from FERC’s Section 203 change-of-control approval.

No Blanket Foreign Ownership Cap

Unlike some other US-regulated sectors (eg, broadcasting, certain aviation and maritime activities), there is no statutory cap on the percentage of a renewable energy project or company that may be foreign-owned.

The US renewable generation sector operates within a wholesale/retail electricity market structure that long predates renewables but has been reshaped by their growth.

Market Structure

About two-thirds of the country’s electricity flows through organised wholesale markets run by regional transmission organisations (RTOs) or independent system operators (ISOs) – PJM, MISO, ERCOT, the California Independent System Operator (CAISO), ISO New England (ISO-NE), NYISO and Southwest Power Pool (SPP) – which operate day-ahead and real-time energy markets, and in most cases capacity markets, under FERC-approved tariffs.

ERCOT is the notable exception in being almost entirely intrastate and outside FERC’s jurisdiction, giving Texas a distinct regulatory posture. The remainder of the country (much of the Southeast and West) operates on a more traditional vertically integrated utility model, where a single utility owns generation, transmission and distribution and sells to captive retail customers under state-regulated rates, with resource decisions made through utility integrated resource planning rather than competitive wholesale markets.

Renewable generation participates differently depending on which structure applies: in RTO/ISO regions, renewable projects typically sell into wholesale markets or under bilateral PPAs with corporate or utility offtakers; in vertically integrated regions, renewable developers more often sell directly to the incumbent utility under a long-term PPA or build assets the utility itself owns and rate-bases.

Key Parties

IPPs and developer-sponsors (ranging from specialised renewable developers to infrastructure funds and oil and gas majors diversifying into renewables) build and often retain ownership of utility-scale wind, solar and storage assets. Investor-owned utilities remain major owners of generation in vertically integrated states and increasingly acquire operating renewable assets in restructured states as well.

Corporate offtakers, especially technology and data-centre companies, have become major demand-side participants, entering PPAs or directly acquiring generation assets to meet clean energy and reliability commitments. Tax equity investors (banks and large corporates) remain central to renewable project finance, given that federal tax credits are typically monetised through partnership structures or, since the IRA, through direct credit transferability. RTOs/ISOs themselves, along with NERC (reliability) and FERC (wholesale market and transmission oversight), round out the key institutional actors.

Assets

The core asset classes are utility-scale solar PV, onshore wind (and a smaller offshore wind fleet concentrated on the East Coast), hydropower (largely federally licensed dams), and a rapidly growing battery energy storage fleet increasingly co-located with solar and wind to firm output and capture value across multiple market products (energy arbitrage, capacity, ancillary services).

Transmission infrastructure, both existing high-voltage lines and a pipeline of new interregional projects, is an increasingly binding constraint and a growing asset class in its own right, given how much renewable development is stalled in interconnection queues awaiting adequate grid capacity.

Applicable Rules and Regulations

FERC-jurisdictional generator interconnection procedures (recently reformed to address multi-year queue backlogs) govern how new renewable projects connect to the grid; RTO/ISO market rules govern participation, bidding and compensation once connected; and state RPS, clean energy standards or utility resource planning requirements shape underlying demand for renewable generation in the first place.

Federal tax credits (Sections 45Y/48E, as modified by the OBBBA) remain the single most important driver of project economics, layered on top of, rather than replacing, the market and regulatory structure described previously.

Unlike electricity, the US market for gas from renewable sources is driven less by traditional utility regulation and more by environmental credit monetisation; the value of the underlying commodity gas is often secondary to the value of the credits it generates.

Market Structure

RNG, also called biomethane, is produced by capturing biogas from landfills, livestock manure, wastewater treatment or organic waste digestion and upgrading it to pipeline-quality gas. Landfill gas is the dominant feedstock, accounting for roughly two-thirds of US RNG production, with dairy and livestock manure digesters a fast-growing second category given their more favourable credit economics.

Producers typically inject upgraded gas into the existing interstate or local natural gas pipeline network under an interconnection agreement with the pipeline operator, and RNG then moves through that same commingled gas grid to end users; because pipeline gas is fungible, RNG’s environmental attributes are tracked and sold separately from the physical gas itself, largely through book-and-claim or similar attribute-tracking mechanisms rather than physical delivery to a specific buyer.

Key Parties

Independent RNG developers and waste management companies (including several major landfill operators) are the principal producers, often through joint ventures or long-term feedstock agreements with landfill owners or dairy farms. Interstate and local natural gas pipeline operators provide the injection infrastructure and interconnection approvals.

Obligated parties under the federal Renewable Fuel Standard (RNS; typically refiners and fuel importers) and, in states with a low carbon fuel standard (LCFS), in-state fuel providers, are the ultimate buyers of the environmental credits RNG generates, even though they never physically receive the gas. Heavy-duty transportation fleets (particularly waste and transit fleets running on compressed natural gas) are significant end users of RNG as a vehicle fuel, which is currently the highest-value use case given the credit structure described in the following.

Assets

Core assets are the digester or landfill gas collection systems themselves, gas upgrading/conditioning equipment (removing CO₂, moisture and contaminants to reach pipeline specification), and the pipeline interconnection infrastructure connecting a project to the gas grid. A smaller category of “green gas” projects uses power-to-gas or biomass gasification pathways, though these remain far less common than landfill- and manure-based biogas in the US market.

Applicable Rules and Regulations

The federal RFS established RNG as a qualifying transportation fuel pathway generating tradeable RINs (Renewable Identification Numbers), and California’s LCFS has had outsized influence nationally by creating a second, often more valuable, credit market for pipeline-injected RNG used as vehicle fuel. Other states (Oregon, Washington) have adopted similar low-carbon fuel programmes.

Physical interconnection to the gas grid is governed by pipeline tariffs and, for interstate pipelines, FERC’s oversight of interstate gas transportation, though FERC’s direct regulatory role in RNG specifically is far lighter than its role in electricity. RNG projects rely much more heavily on state environmental credit regimes and federal tax incentives (including the Section 45Z clean fuel production credit, as modified by the OBBBA) than on FERC-administered market rules.

Credit market conditions are a significant and current headwind for project economics: LCFS credit values have fallen substantially from a historical high of around USD200 per metric ton of CO₂e to roughly USD60 in recent years, driven by credit oversupply, and RIN and state credit values more broadly can be volatile and are subject to periodic regulatory volume-obligation changes at EPA and the California Air Resources Board (CARB).

Because RNG project returns depend heavily on stacking RIN and LCFS-type credit revenue on top of the underlying gas commodity value, this compression has materially lengthened payback periods and tightened financing conditions for newer projects, even as the underlying pipeline-injection infrastructure and feedstock base continue to expand.

The production sector for heat from renewable sources is a smaller, fragmented segment, with little tradeable market and with consumption mainly being on-site. Direct-use geothermal (space heating, district heating, greenhouses) is concentrated in western states with hydrothermal resources; geothermal heat pumps (GHPs; at least 1.27 million homes and 27,000 commercial buildings) work anywhere via stable ground temperatures, and biomass thermal supplies industrial/district heat mainly in the Northeast/Southeast.

Key parties include:

• geothermal developers and municipalities/district utilities for direct-use;
• heating, ventilation and air conditioning (HVAC) contractors and building owners for GHPs; and
• end users directly for biomass

Assets include wells/piping, boreholes/heat exchangers, combustion equipment and (increasingly regulated) thermal energy network piping. BLM geothermal leasing and NEPA apply on federal land, and no FERC-equivalent economic regulator exists; state environmental/water agencies and occasionally PUCs (for district systems) fill that role. Federal tax credits (geothermal ITC, efficiency credits) drive demand.

Clean hydrogen remains pre-commercial, anchored by the DOE’s regional hub programme (funding for two green-hydrogen-heavy hubs was pulled in 2025). No organised trading market exists – offtake is bilateral. The OBBBA accelerated the Section 45V credit deadline to require construction by 1 January 2028 (from 2033), sharply narrowing the eligible pipeline.

Biofuels (biodiesel, renewable diesel, SAF) are a more mature, blending-obligation-driven market under the federal RFS (RINs) plus state LCFS-type credits; Section 45Z is now the primary federal tax incentive, with the OBBBA extending related producer credits through 2026. Other renewables (tidal, wave) remain pilot-stage, with no dedicated regulatory regime.

Domestic production is regulated mainly at the state/local level: interconnection follows state rules (often IEEE 1547-based), with simplified processes for small systems. Permitting requires local building/electrical permits, National Electrical Code (NEC) compliance and fire-code setbacks.

Compensation varies by state. Traditional net metering persists in some states, while others – notably California’s net energy metering (NEM) successor tariff – have shifted to lower export-rate structures favouring storage pairing. Most states have solar-access laws limiting Homeowners Association (HOA) restrictions, and several regulate residential solar sales/financing practices. Community solar programmes exist in roughly half the states.

The federal residential Section 25D credit (30%) expired at the end of 2025 under the OBBBA, though third-party-owned systems can still indirectly benefit via the commercial Section 48E credit; state credits, rebates and solar renewable energy certificate (SREC) markets continue independently.

Electricity generated from renewable sources is transmitted and distributed through an interconnected network owned and operated by investor-owned utilities, public utilities, independent transmission companies and other transmission owners. Wholesale electricity markets in many regions are administered by RTOs and ISOs, which are responsible for maintaining system reliability, balancing supply and demand, and facilitating access to the transmission system. FERC regulates interstate transmission and wholesale electricity markets, while state regulatory authorities oversee local distribution systems and retail electricity service.

Battery energy storage has become an increasingly important component of the US electricity sector, supporting the integration of renewable generation, improving grid reliability and providing operational flexibility. Storage facilities may operate as standalone projects or be co-located with renewable generation, particularly utility-scale solar projects, and are increasingly participating in wholesale electricity markets where permitted.

Continued investment in transmission infrastructure and grid modernisation is expected to remain critical to accommodating future renewable energy development. Federal and state policymakers, utilities and grid operators continue to pursue transmission upgrades and planning initiatives intended to improve system reliability and support the continued expansion of renewable energy resources.

Grid Congestion

The continued growth of renewable energy generation has increased the importance of transmission planning, grid modernisation and system flexibility. In many regions of the United States, transmission constraints and interconnection queue backlogs have contributed to delays in connecting new renewable energy projects to the electric grid. As a result, transmission planning and interconnection reform remain significant areas of regulatory focus.

Grid operators may also implement curtailment, where transmission constraints or system conditions prevent all available renewable generation from being delivered to the grid. The frequency and extent of curtailment vary by region, depending on transmission capacity, market conditions and the operational characteristics of the applicable electricity system.

Grid Flexibility

Grid operators use a variety of operational tools to maintain system reliability, including demand response programmes, energy storage, economic dispatch and other market-based mechanisms. Battery energy storage has become an increasingly important resource for balancing intermittent renewable generation and supporting overall grid reliability.

Off-grid renewable energy systems remain relatively limited but are used in certain remote locations, industrial facilities and resilience applications where connection to the electric grid is impractical or uneconomical.

RNG and biogas are generally transported through existing natural gas pipeline infrastructure once applicable quality standards and interconnection requirements have been satisfied. Pipeline operators and state and federal regulators oversee the transportation of renewable gas in accordance with applicable safety and operational standards.

The regulatory framework governing pipeline access, gas quality and interconnection varies depending on the location of the project and the applicable pipeline operator. In certain jurisdictions, renewable gas may also benefit from state-specific programmes encouraging its injection into existing gas distribution systems.

Renewable heat infrastructure is relatively limited in the United States compared with renewable electricity infrastructure. Geothermal heating systems and biomass facilities operate in certain regions, while district heating networks remain uncommon and are typically developed at the local level.

The regulation of renewable heat projects depends on the applicable technology and is generally addressed through state and local permitting, environmental and building requirements rather than a comprehensive federal regulatory framework.

Infrastructure for hydrogen and other renewable fuels continues to develop across the United States as public and private investment increases. Current projects include hydrogen production facilities, storage systems, transportation infrastructure and renewable fuel distribution networks, although many remain in the early stages of development.

The regulatory framework varies depending on the fuel and infrastructure involved and may include federal and state requirements relating to environmental protection, pipeline safety, transportation and permitting. Continued infrastructure investment is expected to support the commercialisation of hydrogen and other low-carbon fuels in the coming years.

Renewable electricity is supplied to end users through a combination of competitive and traditionally regulated electricity markets. Market participants include investor-owned utilities, public utilities, retail electricity suppliers, IPPs, community choice aggregators (where applicable) and corporate purchasers.

Renewable electricity is commonly sold under PPAs, utility procurement programmes and retail supply arrangements. In competitive wholesale markets administered by RTOs and ISOs, electricity may be traded through organised markets or bilateral contracts. In regulated markets, renewable generation is commonly procured by utilities pursuant to integrated resource planning and state regulatory requirements.

The sale and supply of electricity are regulated through a combination of federal and state laws. FERC regulates wholesale electricity markets and interstate transmission, while state PUCs oversee retail electricity markets, utility service and consumer protection within their respective jurisdictions.

RNG is supplied to utilities, transportation providers, industrial users and commercial customers through existing natural gas infrastructure. Market participants include project developers, gas producers, pipeline operators, utilities and end users.

Commercial arrangements typically address gas supply, pipeline interconnection, transportation services and the allocation of environmental attributes. The market is regulated through federal and state laws governing pipeline operations, environmental compliance and natural gas transportation.

Renewable heat represents a relatively limited market in the United States. Geothermal systems and biomass facilities provide renewable heating in certain regions, while district heating networks are generally limited to specific institutional or municipal developments.

The supply of renewable heat is primarily governed by state and local laws applicable to the relevant technology, together with environmental, building and permitting requirements.

Markets for hydrogen and other renewable fuels, including renewable diesel, SAF and other low-carbon fuels, continue to develop in response to growing demand from the transportation, industrial and aviation sectors.

Commercial transactions are typically structured through long-term supply agreements and other negotiated commercial arrangements. Depending on the fuel involved, market participants must also comply with applicable federal and state regulatory requirements governing production, transportation and environmental compliance.

Renewable Energy Certificates

Renewable energy certificates (RECs) represent the environmental attributes associated with renewable electricity generation and are widely used throughout the United States to demonstrate compliance with renewable energy requirements and voluntary sustainability commitments. REC markets operate through a combination of state RPS programmes and voluntary markets, with environmental attributes generally tracked through regional certificate registries. Depending on the applicable state regulatory framework, RECs may be sold together with the underlying electricity or separately as distinct environmental commodities.

Corporate PPAs

Corporate PPAs have become an established mechanism for procuring renewable electricity, particularly for large commercial and industrial consumers seeking long-term price certainty and the ability to meet sustainability and decarbonisation objectives. Corporate PPAs have also become an important source of revenue certainty for renewable energy projects and frequently support project financing by providing predictable long-term cash flows.

Both physical and virtual PPAs are commonly used in the United States, with the appropriate structure depending on the location of the project, the applicable electricity market and the commercial objectives of the parties. Although contractual terms vary, corporate PPAs typically address pricing, delivery obligations, environmental attributes, credit support, change in law, force majeure, default and termination rights.

Permitting and Development

The United States has a mature onshore renewable energy market, with utility-scale solar, onshore wind and battery energy storage projects developed across multiple states. Project development typically involves developers, landowners, utilities, IPPs, lenders, contractors and government authorities.

Project development generally begins with site selection and land acquisition or leasing, followed by environmental review, permitting, interconnection studies and project financing. Depending on the location and characteristics of the project, approvals may be required from federal, state and local authorities. Projects located on federal lands are also subject to additional permitting and environmental review requirements.

Project Agreements

Engineering, procurement and construction (EPC) agreements, operation and maintenance (O&M) agreements, equipment supply contracts and PPAs remain the principal contractual arrangements used throughout project development and operation. Community engagement has also become an increasingly important component of the permitting process, particularly for large-scale renewable energy facilities where local support may influence project timelines and approvals.

The offshore wind sector in the United States continues to develop, although it remains less mature than the onshore renewable energy market. Development activity has been concentrated primarily along the Atlantic coast, with additional opportunities under consideration in the Pacific region and the Gulf of Mexico.

Offshore renewable energy projects are subject to a comprehensive federal and state regulatory framework involving multiple agencies responsible for leasing, environmental review, permitting, navigation and marine resource management. Project development typically requires co-ordination among developers, regulators, transmission operators, contractors and other stakeholders throughout the planning, construction and operational phases.

Contracting structures commonly include turbine supply agreements, EPC agreements, balance of plant (BoP) contracts and O&M agreements. Because offshore projects involve significant capital investment and complex permitting requirements, project development timelines are generally longer than for comparable onshore facilities.

Renewable project finance follows standard non-recourse structures (SPV borrower, security over project assets, contracts and equity) but carries distinct legal considerations. Tax equity remains central – most projects still monetise credits through partnership flip or sale-leaseback structures, or via IRA-enabled direct transferability, adding structuring complexity not seen in conventional project finance.

The OBBBA’s accelerated 45Y/48E timelines and FEOC restrictions now require careful construction-start documentation and buyer/investor diligence to preserve credit eligibility and avoid recapture risk. Revenue certainty depends on the offtake structure (PPA, hedge, or merchant exposure), with lenders scrutinising curtailment, basis and interconnection risk more heavily than for conventional generation given renewables’ intermittency and queue-related delays.

Permitting and litigation risk (federal land approvals, environmental challenges) is currently elevated relative to historical norms. Storage-specific risk (degradation, warranty, safety) and, for hydropower, FERC licence conditions add technology-specific diligence layers absent from most other asset classes.

Federal Incentives

Renewable energy projects in the United States benefit from a combination of federal, state and local incentive programmes. At the federal level, the principal incentives include the ITC, the PTC and other tax incentives available to qualifying renewable energy projects and related technologies, as modified by the OBBBA and subsequent administrative guidance.

These programmes continue to play an important role in project economics and financing, but sponsors and investors are placing greater emphasis on technology-specific eligibility, construction-start timing, domestic content, transferability and other compliance requirements.

State and Local Programmes

Many states also provide additional support through RPS, grants, tax incentives, loan programmes and other renewable energy initiatives. Because these programmes differ among jurisdictions, the incentives available to a particular project depend on its location, technology and applicable state regulatory framework.

Developers typically evaluate available federal, state and local incentives during the early stages of project development, as these programmes may influence project structure, financing arrangements and long-term commercial viability. The availability and application of incentives are also an important consideration for lenders and investors when assessing project economics and the overall bankability of renewable energy projects.

State incentive programmes also continue to evolve in response to local policy objectives, electricity market conditions and economic development priorities. As a result, developers frequently evaluate both federal and state incentive programmes together when determining project location, financing structure and long-term commercial strategy.

Decommissioning requirements for renewable energy projects are primarily governed by project agreements, permit conditions and applicable federal, state and local laws. Requirements vary depending on the technology, project location and land ownership arrangements.

Developers are commonly required to remove project infrastructure, restore the site and comply with applicable environmental obligations at the end of a project’s operational life. In many jurisdictions, financial assurance or other security may also be required to ensure that decommissioning obligations are satisfied.

The near-term outlook is shaped less by new targets, as the USA has no binding national renewable target, and more by how current legal and policy uncertainty resolves. The RENEW Northeast appeal (1st Circuit) and related offshore wind and Department of Defense (DOD) permitting litigation remain unresolved and will determine whether federal permitting restrictions persist.

Treasury is expected to issue revised “beginning of construction” guidance following the Oregon Environmental Council ruling, which could again narrow safe-harbour options for wind and solar. FERC’s large-load interconnection rule-making (addressing data-centre demand) and continued interconnection queue reform remain pending priorities. Congressional permitting reform talks continue but have stalled repeatedly amid disputes over offshore wind.

At the state level, expect continued expansion of transmission planning initiatives, storage procurement mandates and NEM-style successor tariffs as more states follow California’s lead. Watch points include:

• further FEOC guidance affecting deal structuring;
• the durability of court-ordered permitting relief; and
• whether AI/data-centre demand growth prompts new federal action on transmission siting or reliability standards.