US Power EPC Market Size & Share Analysis - Growth Trends and Forecast (2026 - 2031)

US Power EPC Market Trends and Insights

Inflation Reduction Act–Linked Clean-Energy CAPEX Boom Reshapes Project Finance

A cumulative USD 89 billion in clean-energy announcements during 2024-2025 compressed procurement cycles to 12-15 months, requiring EPC firms active in the US power EPC market to order inverters and transformers before debt close.^{[1]U.S. Department of the Treasury, “Inflation Reduction Act Tax Credit Guidance,” treasury.gov} Liquidated-damages bonds linked to commercial-operation milestones now place schedule risk squarely on contractor balance sheets. Domestic-content bonuses encourage suppliers such as Fluor and Kiewit to lock in U.S.-made modules, narrowing vendor pools and favoring firms with long-term purchase agreements. Modular construction that parallelizes site work with factory fabrication is gaining prominence because it mitigates late-stage delivery slippage. These dynamics reinforce a shift toward lump-sum turnkey structures that guarantee price but reward execution certainty across the US power EPC market.

Multi-GW Data-Center and Green-Hydrogen Load Additions Drive Behind-the-Meter EPC

Hyperscale operators signed more than 15 GW of PPAs in 2025, frequently co-locating 200-500 MW solar-plus-storage systems on adjacent parcels to bypass utility queues.^{[2]Bloomberg News, “Tech Giants Sign Record Energy Deals,” bloomberg.com} EPC contractors are packaging design-build-operate offerings with 20-year availability guarantees, generating 12-15% margins—double typical utility-scale levels. Green-hydrogen projects mirror this model; electrolyzer additions reached 2.5 GW in 2025, and turnkey scopes now bundle power-island design with compression, storage, and pipeline tie-ins. Firms with combined petrochemical and renewable portfolios such as Bechtel, Zachry, and McDermott hold an execution advantage in the rapidly expanding US power EPC market.

Replacement Wave for Coal Fleet Over 40 Years Old Accelerates Renewable Conversions

The average U.S. coal unit hit 47 years in 2025, prompting 38 GW of retirements by 2030 concentrated in MISO, PJM, and the Southeast.^{[3]U.S. Energy Information Administration, “Solar and Wind Generation Continue to Grow in 2025,” eia.gov} Converting coal sites to solar cuts EPC outlays 15-20% by reusing interconnection and substation assets and trims permitting to roughly 18-24 months. Indiana Michigan Power’s Rockport conversion illustrates how legacy 765 kV ties can underpin 1+ GW solar-storage complexes. Political support in swing states accelerates approvals, while community retraining programs blunt local opposition, bolstering renewable uptake in the US power EPC market.

Utility Decarbonization Mandates Beyond RPS Targets Create Captive Demand

Carbon-neutrality statutes in California, New York, and Washington oblige utilities to secure 25-30 GW of incremental clean capacity by 2040-2045. Regulated utilities can rate-base assets and earn 9-11% returns, encouraging multi-year master service agreements that stabilize workstreams for EPC partners. Southern California Edison’s 5 GW solar-storage RFP in 2025 weighted bids toward domestic content and union labor, signaling the procurement direction likely to persist across the US power EPC market.

SMR-Ready Balance-of-Plant Standardization Unlocks Serial Production Economies

DOE’s USD 900 million awards propelled NuScale, Bechtel, and Fluor to pre-qualify Gulf Coast yards for factory-built SMR modules, cutting field labor 40% and condensing schedules to 4-5 years. Fixed-price EPC elements transfer overrun risk to contractors in return for 15% margins, which is reshaping nuclear participation strategies. Qualification under NRC Part 52 remains a barrier, keeping the EPC pool small and specialized within the broader US power EPC market.

Green-Steel OEM Turnkey Contracting Emergence Integrates Power and Process Design

Green-steel complexes now bundle 1-2 GW of renewable generation with electrolyzers and DRI furnaces, demanding EPC expertise that spans power-island, hydrogen, and metallurgical scopes. Bechtel’s USD 4.5 billion cost-capped package for Cleveland-Cliffs illustrates how owners shift integration risk to contractors capable of synchronizing solar output with electrolyzer load profiles. Equipment OEMs such as Siemens Energy and Mitsubishi Power are offering combined packages that cut owner engineering costs 20-25%, creating new competition curves inside the US power EPC market.

Scarcity of EPC Labor and Craft Supervision Compresses Margins

The power-construction workforce shrank 12% between 2020 and 2025, triggering 8-10% annual wage inflation for electricians, pipefitters, and operators. Contractors increasingly pivot to cost-reimbursable structures to pass wage risk to owners, yet margin compression still hits 150-200 basis points. Prefabrication facilities—exemplified by Burns & McDonnell’s 200,000 ft² Kansas City plant—lower field-labor intensity 25-30% and cut onsite schedules to 12-15 months, making modularization central to competitiveness in the US power EPC market.

Supply-Chain Bottlenecks for HV Equipment Extend Project Schedules

Lead times for 345 kV-plus transformers stretched to 28-36 months in 2025 because domestic capacity lags demand, and only four U.S. manufacturers hold relevant capability. EPC firms now reserve slots 18-24 months ahead of financial close, accepting 10-15% cancellation penalties to secure delivery. Federal loans under the Defense Production Act will not add meaningful capacity until 2027-2028, maintaining a short-term drag on the US power EPC market.

ERCOT Queue Curtailments and Interconnection Delays Defer 50 GW of Capacity

ERCOT’s cluster-study process accelerated analysis but requires upfront security equal to 100% of network-upgrade costs, keeping nearly 50 GW in suspended status late in 2025. EPC contracts now incorporate suspension clauses that align mobilization with transmission-upgrade completion, pushing project timelines out by 12-18 months and raising carrying costs across the US power EPC market.

Surety-Bond Tightening Post-Megaproject Overruns Raises Financing Costs

After Vogtle overruns topped USD 17 billion, premiums on nuclear and first-of-a-kind EPC bonds climbed 150-200 basis points, while single-project exposure caps dropped to USD 2-3 billion. Smaller contractors without investment-grade ratings face 3-4% bonding costs, effectively excluding them from bids over USD 500 million. This environment channels capital toward proven solar and wind technologies within the US power EPC market.

Segment Analysis

By Technology: Renewables Consolidate Dominance Across Generation EPC

Renewables captured 80.8% of Power Generation EPC value in 2025, and this share is forecast to widen on a 5.8% CAGR through 2031, underpinning the largest slice of the US power EPC market size for generation.^{[4]U.S. Energy Information Administration, “Solar and Wind Generation Continue to Grow in 2025,” eia.gov} IRA incentives lower solar and wind LCOE to USD 25-35/MWh, squeezing combined-cycle gas economics. Battery storage turned into the fastest-growing sub-segment as standalone BESS reached 8 GW in 2025, creating a need for contractors versed in NFPA 855 compliance. Offshore wind will expand after 2027 once Jones Act–compliant vessels enter service, although near-term revenue remains modest. Geothermal and SMR niches add diversity but stay sub-scale before 2030.

Thermal generation accounted for 15% of 2025 spend and will inch forward at only 1.2% CAGR because coal-to-gas switching has largely played out, while nuclear sits at 4.2% share and relies mainly on SMR demonstrations and license extensions. Contractors that master modular nuclear construction and high-temperature gas-turbine retrofits stand to capture incremental value but will contribute a smaller fraction to overall US power EPC market share growth.

Note: Segment shares of all individual segments available upon report purchase

By Capacity Band: Utility-Scale Projects Anchor Value, DERs Lead Growth

Projects above 500 MW controlled 71.5% of 2025 spend, representing the deepest pool within the US power EPC market size for capacity bands. Unit costs of USD 900-1,100/kW and streamlined FERC permitting sustain their economic edge. The 100-499 MW bracket captures 18% share, serving midsize IPPs and municipal utilities. Distributed assets under 100 MW account for 10.5% of 2025 value yet are poised for a 5.3% CAGR, the swiftest across bands, as manufacturers and data-center operators hedge congestion risk with on-site solar-plus-storage.

California and Texas lead DER adoption thanks to time-of-use pricing that rewards behind-the-meter dispatch. EPC contractors are monetizing premium 12-15% margins by bundling O&M guarantees. Accelerated depreciation under IRA Section 48 further brightens the growth trajectory for these smaller projects inside the US power EPC market.

By End User: Regulated Utilities Sustain Largest Share and Growth Momentum

Regulated utilities held 63.1% of 2025 outlays and are projected to increase at a 3.7% CAGR through 2031, preserving the largest segment of US power EPC market share. State commissions allow cost recovery plus an authorized return, making renewables an earnings driver. IPPs occupy 22% share but face merchant-price volatility that curbs appetite for lengthy builds, steering them toward flexible hybrid plants. Industrial captive power absorbs 9.5% of spend, notably in chemicals, steel, and tech, where reliability premiums justify microgrid investments. Public entities round out 5.4%, often using turnkey EPC to streamline procurement. FERC Order 1920’s long-range planning adds substantial transmission work for all utility classes and reinforces demand depth throughout the US power EPC market.

Geography Analysis

Texas, California, and the Midwest generated roughly 55-60% of 2025 capacity additions, anchoring regional leadership within the US power EPC market. ERCOT brought 8.5 GW online, mainly in West Texas and the Panhandle where 345 kV corridors carry surplus capacity. CAISO added 4.2 GW, but solar curtailment during spring days has popularized hybrid plants that shift energy to evening peaks. MISO delivered 3.8 GW, benefiting from wind resources and coal-plant retirements even though network upgrades valued at USD 15-20 billion remain essential.

PJM logged 3.1 GW in 2025, with Atlantic offshore wind poised for mid-term growth once vessel constraints ease. The Southeast added 2.7 GW, leveraging land availability and 4-6 hour batteries to manage intermittency. The Pacific Northwest’s 1.9 GW expansion leverages hydro balancing but contends with lengthy NEPA reviews that extend schedules. High land costs kept the Northeast to 1.2 GW, yet FERC Order 2023 reforms promise to unlock 5-7 GW of delayed projects by 2028.

Labor and material costs vary sharply by region. Texas and California command 15-20% wage premiums, pressuring margins, while the Midwest enjoys cheaper labor and robust apprenticeship pipelines. Transmission investment tilts toward MISO and SPP, which plan USD 30 billion of upgrades, whereas ERCOT and CAISO require USD 20 billion combined. These disparities influence bidding strategies and capital allocation patterns in the US power EPC market.