This dashboard summarizes a facility-level techno-economic analysis of off-grid renewable-powered industrial heat systems. Under the paper's assumptions on technology costs, fuel prices, and local siting potential, modeled opportunities are concentrated in food, chemicals, pulp and paper, refining, and metals.
Industrial heat includes steam, hot water, hot air, and direct process heat used in manufacturing. It accounts for most final energy use in U.S. industry and is still supplied predominantly by fossil fuels, especially natural gas.
Industrial process heat contributes roughly ~10% of U.S. greenhouse-gas emissions. The paper examines whether a substantial share of that demand can be shifted to lower-emissions electric heat supply without increasing delivered heat cost.
For each facility, the paper compares delivered heat costs for natural gas, heat pumps, and off-grid renewable systems paired with thermal energy storage (TES), while retaining the existing gas boiler for backup. The siting screen evaluates solar and wind potential within a 15×15-mile buffer around each facility.
The paper implies three practical needs: support for early commercial deployment, faster siting and permitting for industrial-adjacent renewable projects, and financing aligned with 20–25-year industrial asset lives. See § 05 — Policy levers.
Solar and wind are screened within a 15×15-mile buffer around each facility and modeled as behind-the-meter supply. In this configuration, new transmission interconnection is not required. The median analyzed site has roughly 60× more solar potential than annual heat demand.
Heat pumps are modeled only for low-temperature service (≤200 °C), with coefficient of performance (COP) ≈ 1.9. Electric thermal storage (TES) is evaluated across all temperature ranges; the model assumes 4 hours of storage for low-temperature applications and 15 hours for medium- and high-temperature applications.
The modeled system does not retire existing gas boilers. Instead, the gas connection remains available during periods of low renewable output, so reliability is maintained through redundant supply pathways.
Typical U.S. transmission interconnection wait times have risen to approximately five years, and queued capacity now exceeds the existing installed fleet (Lawrence Berkeley National Laboratory [LBNL], Queued Up 2024). For industrial operators with capital-planning horizons measured in years, that delay constrains deployment of grid-tied renewables.
The paper therefore evaluates an alternative: solar or wind sited within a 15×15-mile buffer of each facility and connected behind the meter. Across the analyzed facilities, the median site has access to roughly 60× more solar generation potential than annual heat demand (first quartile: 20×). Only 73 facilities, or 2.1% of the sample, lack sufficient nearby solar potential for full coverage, but those facilities account for about 27% of total heat demand.
Behind-the-meter siting removes projects from the transmission interconnection queue and avoids grid delivery charges embedded in retail electricity prices. The discussion also notes an operational flexibility benefit: thermal storage can absorb the lower-value fraction of renewable output, potentially reserving higher-value output for grid export where allowed.
Industrial heat loads require continuous supply. The modeled configuration does not assume retirement of existing gas infrastructure; the gas boiler remains in service when solar and wind output is insufficient. In this framework, solar, wind, and thermal storage provide the primary heat supply, while gas provides dispatchable backup. Reliability is therefore maintained through redundancy rather than full substitution.
Green hydrogen remains relevant for some very high-temperature processes and applications that require combustion chemistry, but the paper's discussion indicates materially higher delivered heat cost than the electrification pathways shown here under current assumptions.
Carbon capture and storage (CCS) addresses emissions while retaining combustion equipment, but it depends on capture systems, transport infrastructure, and access to storage sites. By contrast, the off-grid electrification pathway evaluated here focuses on reducing delivered heat cost and emissions through local renewable supply and thermal storage.
Grid-tied electrification may deliver similar end uses, but its deployment timeline is affected by transmission availability and interconnection delays. That timing constraint is one reason the paper evaluates an off-grid configuration.
| Facility | State | Industry | Temp | Demand (TBtu/yr) | Savings (%) | Solar Headroom |
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Industrial heat-pump and thermal-storage installations at this scale remain early-commercial. Demonstration grants, cost-share, and concessional debt can reduce first-mover risk while costs and supply chains mature.
The median facility has far more nearby solar potential than annual heat demand within the screened buffer, but a small share of sites remain land-constrained. State and local siting rules therefore materially affect whether modeled potential can be built.
Industrial gas assets are long-lived. Standard 7–10-year commercial loans increase annualized cost pressure on capital-intensive clean heat projects, whereas longer-tenor instruments better reflect plant life.
Public procurement can create early markets for lower-carbon industrial products, especially in cement, steel, glass, and chemicals, where buyers can reward lower-emissions production pathways.
This panel reproduces the structure of Figure 4A of the paper. Adjust solar or wind capital expenditure (CAPEX), capacity factors, gas price, thermal energy storage (TES) CAPEX, and related parameters to recompute the levelized cost of heat (LCOH) for three representative processes: a steam boiler at 150 °C, an ethane cracker at 850 °C, and a glass melter at 1200 °C.
Use the results to examine sensitivity to input assumptions rather than as a site-specific engineering estimate. Default values reflect the paper's scenario assumptions for the selected year.