The United States has directed over $1.8 trillion in public funding toward energy technologies over the past 50 years — through tax credits, research spending, grants, loans, and regulatory mandates. This dashboard tracks where that money went, how much each technology received, and whether the funding came from government budgets or was mandated between private parties.
What this is: A retrospective comparison of cumulative U.S. public funding directed at fourteen energy technology categories from 1975 to 2025, measured as annual flows in real 2024 dollars. "Public funding" includes federal R&D appropriations, federal tax credits and expenditures, direct grants and demonstration programs, loan guarantees, transfer payments (LIHEAP, WAP), state-level regulatory compliance costs (RPS, EERS), ratepayer cost transfers (NEM, utility efficiency, LCFS, state clean energy fund surcharges), below-market pricing of public resources (O&G leasing, PMA electricity), and above-market mandated costs (RFS, uneconomic dispatch). The dashboard distinguishes ~$1.0 trillion with government budget impact from ~$718 billion in regulatory cost transfers with no budget impact. It does not measure downstream benefits, cost per unit of energy, or policy effectiveness.
Data sourcing: Approximately 86% of dollar-weighted values are anchored to government or credible institutional source data. "Anchored" means the annual value for that year comes directly from a published source rather than interpolation between benchmarks. Each stream is rated HIGH (90%+ of dollar-years sourced directly), MID (70–80%), or LOW (50–60%); the 86% figure is the dollar-weighted average across all 72 streams. Principal government sources: EIA subsidy reports, JCT tax expenditure pamphlets, DOE budget documents, Treasury §1603 project-level awards, USASpending.gov, GAO annual tax data, IEA Energy Technology RD&D database, LBNL state compliance cost data, CRS RL31865 (LIHEAP), ONRR revenue data, ACEEE State Scorecard (utility EE), and CARB monthly credit transfer reports (LCFS). The principal estimates without direct government sourcing are: solar net metering ($30–65B, LBNL/Brattle/CPUC) and state clean energy fund surcharges ($53B, compiled from DSIRE and state reports). The v19 source data spreadsheet provides specific citations for every stream.
R&D comparability note: R&D figures use the full DOE program office budget authority, which includes national laboratory operating costs. This treatment is consistent across all technologies, but the lab share of total R&D varies: nuclear R&D is dominated by Idaho National Laboratory ($1.6B+/yr), while solar and wind R&D includes NREL operating costs ($687M/yr in FY2025) alongside university and industry grants. Under EIA's narrow definition (grants to non-federal recipients only), nuclear R&D would be roughly $15-25B rather than $74-94B. Solar and wind would also decrease, but by a smaller factor. See the Methodology tab for details.
What to watch for: Cumulative totals without time normalization can mislead. Oil & gas tax provisions have been in force for 100+ years; solar ITC at meaningful scale for only ~16 years. The scorecard separates "Tax Credits" (dollar-for-dollar credits and excess deductions, where the full face value represents the public cost) from "Tax Acceleration Benefits" (timing differences such as IDC expensing, where the taxpayer receives the same total deduction on an accelerated schedule). Roughly half of oil and gas tax expenditures ($45–70B) are acceleration benefits rather than direct transfers. See the scorecard footnotes for details.
What is excluded: Major exclusions include MACRS accelerated depreciation ($5–8B, shown as dashed overlay on charts), §45X Advanced Manufacturing ($30.6B), ATVM automotive loans ($20B+), EV consumer credits ($40–70B projected), Price-Anderson nuclear liability cap ($25–75B), capacity market payments (~$10–15B/yr), SPR ($40–50B), and state property/sales tax exemptions ($7–15B). Including all exclusions would add several hundred billion. See the Methodology tab for the complete list with rationales.
Each chart shows estimated annual public funding flows in real 2024 USD, stacked by type. Values represent mid-range estimates from CRS R&D data, EIA public funding reports, JCT tax expenditures, LBNL RPS compliance data, and Synthesis from government sources. Hover for year-by-year breakdown.
Click any chart header to expand it to full width. Hover over chart stream labels in the legend to see the primary source document. Shared y-axis enables cross-technology comparison; individual y-axis reveals internal composition of each technology's funding mix.
Each chart shows annual flows in real 2024 dollars for all funding streams within a technology. Solid fills are anchored to government source data (EIA, JCT, DOE, Treasury, ONRR, LBNL); lighter fills indicate interpolated estimates between anchor years. Dashed overlays show MACRS accelerated depreciation (excluded from totals). Grant and loan streams use discrete keyframes (zero in non-anchor years); continuous policies (R&D, tax, RPS) use linear interpolation. See the Methodology tab for complete source citations, anchor percentages, and estimation methodology for every stream.
Net metering is a ratepayer cost transfer: distinct from a government expenditure: excluded from EIA federal inventories. Included here as a state policy instrument with measurable distributional effects.
| Technology | R&D | Tax Credits (direct transfer) | Tax Accel. Benefits (timing difference) †† | Grants/DOE | Loan Guar. | RPS/State | Net Metering † | ZECs/Mandates | Total |
|---|---|---|---|---|---|---|---|---|---|
| Nuclear | $74–94B | $10–22B | ~$0 | $1–2B | $8–12B | $10–20B | N/A | $8–15B | ~$105–150B |
| Solar | $15–22B | $35–55B | ~$0 | $13–20B ‡‡ | $14–20B | $45–65B | $30–65B | $7–12B | ~$185–315B |
| Wind | $4–7B | $25–40B | ~$0 | $17–22B ‡‡ | $5–10B | $40–60B | $1–3B | $2–4B | ~$95–150B |
| CCS | $10–16B | $3–8B | ~$0 | $3–6B | $2–5B | Not quantified ‡ | N/A | $1–3B | ~$20–40B |
| Battery | $2–4B | $2–5B | ~$0 | $3–6B | <$0.5B | $2–5B | N/A | $2–5B | ~$8–20B |
| Geothermal | $5–8B | $4–8B | ~$0 | $1–2B | $0.3–0.5B | $3–6B | N/A | $1–3B | ~$10–22B |
| Coal | $30–40B | $18–26B | $4–6B | $6–10B | <$0.5B | Not quantified | N/A | $15–25B | ~$75–105B |
| Oil & Gas | $8–14B | $55–90B | $45–70B | <$0.5B | <$0.5B | Not quantified | N/A | $35–50B | ~$165–230B |
| Efficiency * | $35–55B | $20–40B | ~$0 | $25–35B § | N/A | $200–260B | N/A | $150–200B §§ | ~$400–600B |
| Biofuels | $10–16B | $80–110B | ~$0 | $1–2B | <$0.5B | $220–260B | N/A | $15–30B | ~$280–420B |
| Hydrogen | $6–9B | <$0.5B | ~$0 | $4–8B | $0.5–1B | N/A | N/A | N/A | ~$8–18B |
| Hydropower | $0.5–1B | <$0.5B | ~$0 | <$0.5B | N/A | N/A | N/A | $6–10B | ~$7–14B |
| Biopower | N/A | $1–3B | N/A | N/A | N/A | $5–12B | N/A | N/A | ~$6–15B |
| Grid & Tx | $10–18B | N/A | N/A | $10–15B | <$0.5B | N/A | N/A | N/A | ~$20–35B |
† Net metering represents a retail-rate cost transfer from non-solar to solar ratepayers, distinct from a government expenditure. estimated: $30–65B national cumulative 1995–2025. CA CPUC data ($3.4B/yr in 2021, $8.5B/yr in 2024) provides the largest state anchor; CA represents roughly 40–50% of U.S. distributed solar capacity. National extrapolation carries high uncertainty. See Methodology tab.
†† Tax Acceleration Benefits vs. Tax Credits: "Tax Credits" covers provisions where the full JCT-reported amount represents a genuine public cost, either a dollar-for-dollar credit (ITC, PTC, §45U, §45Q, §48C, EOR §43, refined coal §45, non-conventional fuels §29) or an excess deduction above actual costs. For percentage depletion, JCT reports only the amount exceeding cost depletion, which represents a real transfer rather than a timing difference. "Tax Acceleration Benefits" allow deductions to be taken earlier than standard schedules. The taxpayer receives the same total deduction either way, but on an accelerated schedule; JCT reports the NPV of the timing difference. For oil and gas, this includes IDC expensing (~$40–60B cumulative; immediate deduction vs. 7–15 year capitalization) and G&G amortization (~$3–5B; 2-year vs. 7-year writeoff). For coal, this includes a small depletion acceleration component (~$4–6B). For renewables, MACRS 5-year depreciation ($5–8B cumulative) is excluded from totals and shown as a dashed overlay. Both columns use JCT methodology; the distinction is in the economic mechanism.
‡‡ Solar and Wind Grants/DOE: §1603 streams sourced from Treasury project-level awards data (10,012 awards, $26.16B total nominal). Wind §1603 was heavily front-loaded (FY2009–2013), solar §1603 back-loaded (peaking FY2014). Treasury cumulative: wind $13.0B nom ($17.4B 2024$), solar $10.3B nom ($13.3B 2024$), geothermal $0.76B nom ($1.0B 2024$).
Oil & Gas tax: GAO RCED-00-301R annual JCT data shows O&G tax expenditures peaked at $10.1B/yr in 1982 during the drilling boom. Tax Credits ($55–90B): percentage depletion excess over cost basis (~$30–45B cumulative; JCT reports only the excess, which represents a genuine transfer), EOR credit §43 (~$5–10B), and non-conventional fuels credit §29/§45K (~$15–25B, mostly FY1999–2013 for coalbed methane and tight gas). Tax Acceleration ($45–70B): IDC expensing (~$40–60B; immediate deduction of intangible drilling costs vs. 7–15 year capitalization) and G&G amortization (~$3–5B; 2-year vs. 7-year writeoff). The split is approximate because GAO data for FY1977–2000 reports IDC and depletion combined; the provision-level split is estimated from JCT pamphlet data for FY2001–2009 where individual provisions are visible. In FY2016–2017, O&G tax provisions were net revenue-positive for the government (EIA: $1.1B inflow).
Below-market federal leasing (~$43B): The Mineral Leasing Act of 1920 set the federal onshore O&G royalty rate at 12.5%, where it remained until the IRA raised it to 16.67% for new leases in Aug 2022. The OBBBA (July 2025) reverted to 12.5%. Benchmark: 16.67% (IRA rate; comparable to state rates in UT=16.67%, ND=16.67–18.75%, CO=20%, NM=18.75–25%). Gap = ONRR onshore royalties × (16.67−12.5)/12.5 = royalties × 33.4%. Sources: ONRR revenuedata.doi.gov (FY1982–2025), USGS federal production data (pre-1982), TCS "Royally Losing" reports (2020, 2022), TCS 2025 Year in Review, GAO-24-103676 ($74B royalties 2012–2022). Validates at $1.6B/yr for 2015–2024 vs. TCS's $1.5B/yr. This is a Regulatory Cost Transfer: the below-market pricing of publicly owned resources represents foregone government revenue (and a corresponding cost advantage to lessees), with no direct budget expenditure. Classified identically to how below-market PMA hydroelectric pricing is treated for the hydropower technology.
‡ CCS state support: WY, IL, ND, TX, LA have enacted CCS-adjacent grants, severance tax exemptions for CO₂-EOR, and storage liability frameworks. No defensible aggregate annual series exists.
* Efficiency includes LIHEAP ($185B, toggleable) in the "ZECs/Mandates" column. § Grants = WAP ($26B) + IIJA. §§ ZECs/Mandates column for efficiency = LIHEAP ($185B, toggle). RPS/State column = utility ratepayer programs ($189B) + state clean energy fund surcharges ($53B). Biofuels RPS/State = RFS ($233B) + LCFS ($23B). Hydropower ZECs/Mandates = PMA below-market electricity ($8B).
Coal uneconomic dispatch (~$22B): Above-market cost of running coal plants when cheaper alternatives were available, 2012–2025. Source: RMI Economic Dispatch Dashboard (utilitytransitionhub.rmi.org), based on hourly comparison of coal plant marginal cost (fuel + VOM from EIA-923) against ISO/RTO wholesale market energy price. Gross loss = sum of revenues during months when coal operated below marginal cost. $14.3B cumulative 2012–2022 (nominal, per RMI Jan 2023); ~$3B peak in 2020 (COVID demand collapse). Plants with fuel cost recovery mechanisms (75% of fleet) account for 96% of losses. Southeast utilities account for one-third of losses. This is a Regulatory Cost Transfer: fuel cost recovery clauses in regulated utility rate structures allow above-market coal generation costs to be passed through to ratepayers. Methodologically parallel to RPS compliance costs for renewables. Pre-2012: zero (coal was generally economic vs. gas before the shale revolution). Series will shrink to zero as coal fleet retires.
RPS compliance costs alone total an estimated $80–130B over 2001–2025, yet most federal public funding inventories stop at the state border.
| Type | Programs & States | Est. Cumulative | Status |
|---|---|---|---|
| Zero Emission Credits | NY ($462M/yr, ~$5.5B since 2017), IL ($235M/yr), NJ (~$300M/yr), CT (~$200M/yr), OH ($150M/yr 2019–22, rescinded). Palisades restart: ~$300M MI state + federal DOE loan guarantee support (~$1.5B). | $10–18B | Active |
| Clean Energy Standards | NY CES through 2030, IL CEJA, NJ ZEC extended. Above-market zero-carbon electricity procurement. | Incl. in ZEC | Active |
| State R&D / NYPA | NYPA operating support, NY Green Bank adjacency, state university nuclear engineering programs | $2–4B | Ongoing |
| Type | Programs & States | Est. Cumulative | Status |
|---|---|---|---|
| RPS Compliance Costs | Solar SREC carve-outs in MA, NJ, DC, MD, CT at $200–450/MWh peak. LBNL Aug 2025: solar share rising to ~45% of ~$14.2B/yr national total by 2024. | $55–85B | Ongoing |
| Net Metering † | CA: $3.4B/yr (2021) → $8.5B/yr (2024). NEM 3.0 cut CA compensation 75% (April 2023). LBNL/Brattle: +1.1¢/kWh per 5pp NEM penetration. | $30–65B | Contested |
| State ITCs & Rebates | CA CSI/Go Solar $3.2B (2007-2016). NY-Sun $2.5B+ (2012-2025). SC ITC ~$0.4B. NJ/MA/AZ/CT/OR ~$1.5B. | $5–10B | Mostly sunset |
| Community Solar | IL, NY, MA, MN, NJ, CO above-wholesale compensation. NY NYSERDA $400M+ committed. | $2–5B | Expanding |
| Type | Programs & States | Est. Cumulative | Status |
|---|---|---|---|
| RPS Compliance | Wind captured ~60–70% of early RPS procurement 2000–2015, declining to ~40% by 2024 as solar share rose. TX CREZ transmission build-out: ~$7B ratepayer-funded for wind. | $45–65B | Ongoing |
| Offshore Mandates | NY 9 GW, NJ 7.5 GW, MA 3.2 GW. OREC premiums $30–80/MWh over market. Early stage, accelerating. | $3–8B | Growing |
Note: State and local property tax abatements (TX Ch. 312, IA exemptions, MN/KS/OK wind exemptions) are not included in these totals. See Methodology tab for discussion of the abatement data gap.
| Source | Coverage | Key Contribution |
|---|---|---|
| CRS RS22858 (Clark, 2018) | DOE R&D 1948–2018 by technology | Nuclear = 48% of all DOE energy R&D over 70 years |
| EIA 2007 Table 12 (DOE Budget Authority History) | Annual DOE R&D by category, FY1978–2007 (million 2007$) | Primary source for nuclear, coal+CCT, other fossil, and renewable energy R&D. 30 annual values per technology. Conversion: ×1.42 → 2024$. Source: U.S. DOE Budget Authority History Table by Organization. |
| IEA Energy Technology RD&D Statistics | U.S. solar, wind, geothermal R&D by sub-technology, FY1974–2015 (million 2024 USD) | Primary source for solar/wind/geothermal R&D sub-technology split FY1974–2005. Already in 2024 USD. Exceeds EIA Table 12 total for FY1981–1983, 1986–1987, 1989 (IEA captures broader DOE scope including demonstration programs). Key finding: wind R&D collapsed to $3–25M/yr in FY1989–1992; solar R&D peaked at $1.2B in FY1981. |
| DOE FECM Congressional Budget Justification (FY2023–2025) | Carbon Management Technologies line items: H2+CCS, Transport & Storage, CO2 Removal, CO2 Conversion, Point-Source Capture | CCS R&D = Carbon Management Technologies subtotal ($460M FY2023, $460M FY2024, $436M FY2025) = 52% of total FECM. Prior "60–75% of FECM" estimate was too high. Excludes Resource Sustainability (methane, minerals), Program Direction, and NETL operations. |
| EIA Federal Public Funding FY2022 | All federal energy public funding | FY2022 total ~$18B; solar $7.5B; wind $3.6B; nuclear $390M (pre-§45U) |
| JCT Tax Expenditure Estimates | Annual ITC/PTC/§45U/§45Q | §45U: $13.1B over 2024–2028; solar ITC: $27.5B in FY2024 alone |
| LBNL RPS/CES Compliance Costs (Aug 2025) | State RPS compliance costs (% of retail bill), 27 states, 2007–2024, with solar-specific sub-tiers (SRECs, carve-outs, DG set-asides) | Solar sub-tier share computed from state-level data. Solar = 42–51% of RPS costs (higher than prior 25–35% estimate). Avg compliance cost: 0.3% (2007) → 4.9% (2024) of retail bill. 27 states with Total RPS data, 20 solar-specific sub-tiers identified. |
| LBNL / Brattle (Oct 2025) | Factors in U.S. electricity price increases | 5pp NEM penetration → +1.1¢/kWh nationally; CA NEM → 2¢/kWh |
| CPUC Public Advocates (2024) | CA NEM 1.0/2.0 cost shift | CA cost shift: $3.4B/yr (2021) → $8.5B/yr (2024) |
| Pfund-Healey DBL (2011) | First 15 years of public funding by technology | Nuclear: $3.3B/yr; renewables: $0.4B/yr: 10× disparity in early years |
| GAO RCED-00-301R (2000) | Annual JCT tax expenditure data for IDC expensing and percentage depletion, 1968–2000 | O&G tax expenditures peaked at $10.1B/yr (1982, real 2024$) during drilling boom; went negative in 1988. Enabled 17 annual anchor points replacing interpolation. |
| CRS R41227 (2011) | Historical energy tax expenditures 1977–2010 with inflation-adjusted series | Extends GAO data through 2010; confirms O&G tax expenditure recovery in mid-2000s ($2.7B/yr by 2005) |
| CBO Business Tax Credits for Wind and Solar (Apr 2025) | ITC+PTC cost analysis with MACRS depreciation valuation | MACRS depreciation benefit = ~15% of investment ($54M on $350M project). ITC+PTC deficit impact: $28B in 2025, $308B over 2026–2035 |
| TCS Federal O&G Leasing Reports (2020–2026) | Below-market royalty rate revenue analysis; used for leasing stream | $1.5B/yr foregone revenue at 12.5% vs 16.67% rate (2015–2024); $13.1B gap at 18.75% benchmark (2012–2021); OBBBA reverted rate to 12.5%. Now used as primary validation for below-market leasing stream ($53B cumulative) |
| ONRR Natural Resources Revenue Data (FY1982–2025) | Federal onshore O&G royalty collections, annual fiscal year data | revenuedata.doi.gov; FY2004–2025 from fiscal year dataset, FY1982–2002 from archive dataset. Provides the denominator for below-market leasing gap calculation |
| GAO-24-103676 (Sep 2024) | Federal oil and gas royalty compliance audit | ONRR collected $74B in royalties from federal O&G leases 2012–2022 on $600B total sales. Confirms implied 12.3% effective royalty rate, consistent with 12.5% statutory rate. Cross-validates ONRR royalty series |
| JCT JCX-97-14 (FY2014–2018 Tax Expenditures) | Annual O&G IDC, depletion, G&G, air pollution control; wind §45; solar §48; MACRS | FY2014 O&G IDC+depletion+other = $2.6B nom ($3.0B 2024$); FY2015 = $3.1B nom ($3.5B 2024$). MACRS 5-yr solar/wind = $0.3B/yr (JCT incremental measure). Wind §45 PTC = $1.2–3.6B/yr |
| JCT JCX-55-16 (FY2017–2021 Tax Expenditures) | Annual O&G IDC, depletion; wind §45; solar §48; confirms TCJA effects | FY2017 O&G IDC=$1.6B + depletion=$0.8B = $2.4B nom; cross-validates EIA net-negative position (§199 repeal + base broadening created net revenue despite individual provisions remaining as expenditures) |
| RMI Economic Dispatch Dashboard (2012–2024) | Hourly coal plant economic analysis; used for uneconomic dispatch stream | utilitytransitionhub.rmi.org. $14.3B cumulative gross losses 2012–2022 (nominal); $1–3B/yr; 2020 peak ~$3B (COVID). EIA-923 plant data vs. ISO/RTO wholesale prices. Southeast = 1/3 of losses. CC BY 4.0 license. Updated quarterly |
| CRS RL31865 "LIHEAP: Program and Funding" (2018) | Complete LIHEAP/LIEAP funding table FY1981–2018 | Primary source for LIHEAP annual appropriations. $1.85B (FY1981), $5.1B (FY2009–10 ARRA), $4.7B (FY2011). Extended with LIHEAP Clearinghouse data for FY2019–2026 |
| LIHEAP Clearinghouse (liheapch.acf.gov) | Annual LIHEAP funding releases FY2019–2026 | HHS Office of Community Services. FY2021 ~$8.3B (ARP supplemental); FY2024 $4.1B; FY2026 $4.05B |
| ACEEE State Energy Efficiency Scorecard (annual) | Utility ratepayer-funded efficiency program spending by state | Primary source for national utility DSM spending (~$7–8B/yr by 2020). 26 states + DC have EERS mandates. Annual editions since ~2007. HIGH confidence — anchored to ACEEE Scorecard Figure 2 (1993–2023) |
| NY State Comptroller Report (Aug 2024) | NYSERDA Clean Energy Fund audit | $3.4B spent through 2023; $7.5B ratepayer authorized 2016-2032; ~$440M/yr collections. MD+IR Table 10: $2.0B expended, $937M committed. Pre-CEF: SBC ~$175M/yr (1998-2015). Primary anchor for NY state clean energy fund estimate |
| NJ BPU Clean Energy Program (FY2026 Budget) | New Jersey ratepayer-funded clean energy programs | NJCEP + State Energy Initiatives: $345M new FY2026 funding ($869M total budget incl. carryforward). EE programs $191M, DER $26M, RE $7M, admin $70M, State Initiatives $216M. ~3% of US population |
| CT Green Bank Annual Reports (2012-2025) | Connecticut Green Bank ratepayer-funded subsidies | Subsidies ~$10-15M/yr (purple bar, "Uses of Resources" chart). Loans/leases much larger ($25-55M/yr) but recycled capital, not net public cost. ~1% of US population. ctgreenbank.com strategy-impact reporting |
| Cullenward (Oct 2024) Kleinman Center, UPenn | California LCFS program analysis and cost estimates | "$17.7B in 2023 USD" cumulative LCFS credit value through 2023. Credit price history, pass-through analysis, retail fuel price impacts. Primary validation for state LCFS stream ($24B) |
| DOE Office of Electricity Budget Justifications | Grid modernization, smart grid, energy storage R&D | Annual budget authority for grid R&D stream. Supplemented by IEA RD&D "Electricity T&D" category and CRS RS22858 |
| IIJA P.L. 117-58 §§40101–40107 (Nov 2021) | Grid resilience and transmission programs | GRIP $2.5B, Transmission Facilitation $2.5B, State-Based Grid $3.0B, tribal electrification $0.5B. Primary source for post-2021 grid grants stream |
This report estimates cumulative U.S. federal and state public financial support for fourteen energy technology categories over 1975–2025 in real 2024 dollars. It draws on multiple government sources and independent analyses. All values are order-of-magnitude estimates. Annual figures in the charts are constructed from discrete anchor points with interpolation between them and should not be treated as year-by-year audit-quality data.
The report uses a broad definition of public funding that includes: direct federal appropriations (R&D, LIHEAP, WAP), tax expenditures (credits, deductions), direct grants and loan guarantees, state regulatory compliance costs (RPS, EERS), ratepayer cost transfers (NEM, utility efficiency, state clean energy funds), below-market pricing of public resources (O&G leasing, PMA electricity), and above-market mandated costs (RFS, LCFS, uneconomic dispatch). This is substantially broader than the EIA subsidy definition, which limits scope to programs with an identifiable federal budget impact and excludes most state programs and ratepayer transfers. The dashboard allows toggling each economic function bucket on/off to approximate the EIA scope.
| Technology | DOE Office | Primary Source | Key Anchor Points | Uncertainty |
|---|---|---|---|---|
| Nuclear | Office of Nuclear Energy (NE) | DOE NE Budget page (energy.gov/ne/our-budget); CRS RS22858; GAO EMD-79-52 (1979) | FY1979 peak ~$5.8B; FY2021=$1,508M; FY2022=$1,655M; FY2023=$1,773M; FY2024=$1,685M (all enacted, real 2024$) | Low FY2016+; Medium pre-2000. Note: EIA FY2016–2022 report uses a narrow R&D definition (grants to non-federal recipients only), e.g., FY2016=$183M, FY2022=$259M (2022$). This report uses the broader DOE-NE full appropriation, which is 5–8× larger. The narrow EIA definition excludes national lab operations and intramural research. See EIA Table 5. |
| Solar | Solar Energy Technologies Office (SETO) | DOE SETO FOA announcements; DOE FY2025 Budget in Brief; CRS RS22858 | CRS R40913 enacted (nominal): FY2013=$269.1M, FY2014=$254.3M, FY2015=$230.8M, FY2016=$241.6M, FY2017=$207.6M, FY2018=$241.6M, FY2019=$246.5M, FY2020=$280M, FY2021=$280M, FY2022=$290M base+$80M IIJA=$370M. FY2025 req=$318M | Medium: SETO budget not always publicly broken out separately from EERE total |
| Wind | Wind Energy Technologies Office | CRS R40913 enacted figures (annual series); CRS RS22858 for pre-2010 | CRS R40913 enacted (nominal): FY2013=$86.1M, FY2014=$87M, FY2015=$105.9M, FY2016=$95.5M, FY2017=$90M, FY2018=$92M, FY2019=$92M, FY2020=$104M, FY2021=$110M, FY2022=$114M base+$100M IIJA=$214M. FY2023=$345.4M requested. | Low FY2013+; Medium pre-2009 |
| CCS | Fossil Energy and Carbon Management (FECM) | EIA FY2016-2022 subsidy report (Table A7); CBO 2012 federal fuel support brief | ARRA 2009 ~$3.4B for CCS (multi-year, ~$700M/yr); FECM total ~$750–890M/yr FY2021–2022; CCS-specific subset estimated at ~$400–470M/yr (~52% of FECM total, excluding methane, critical minerals, hydrogen, NETL operations). DOE Statistical Tables FY2008–2015 anchor: Carbon Management Technologies line. | Medium-High: FECM budget mixes CCS with other fossil/carbon programs; CCS-specific subset is estimated. Pre-2010 values interpolated from CRS RS22858. |
| Battery Storage | Vehicle Technologies Office (VTO) + Energy Storage | DOE FY2025 Budget in Brief (VTO=$502M req); DOE FY2023 CBJ (VTO=$602M req) | VTO enacted FY2016~$280M, rising to ~$450M by FY2022; storage-specific ~25–35% of VTO | High pre-2015: VTO includes EVs broadly; grid storage subset is an estimate |
| Geothermal | Geothermal Technologies Office (GTO) | CRS R40913 enacted figures (annual series); CRS RS22858 for pre-2010 | CRS R40913 enacted (nominal): FY2013=$35M, FY2014=$44.8M, FY2015=$54.3M, FY2016=$71M, FY2017=$69.5M, FY2018=$80.9M, FY2019=$84M, FY2020=$110M, FY2021=$106M, FY2022=$109.5M base+$84M IIJA=$193.5M. FY2025 enacted=$488M (IIJA-inflated) | Low FY2013+; Note: FY2025 figure unusually high due to IIJA supplemental appropriations |
| Coal | DOE Fossil Energy, Coal Programs | CRS RS22858; NRC (2001) Fossil Energy Budgets FY1978–2000; DOE FECM budget justifications | FY1979 peak ~$2.2B (real 2024$); Synfuels Corp ~$0.9B (1980–86); Clean Coal Demos ~$6B federal share (1986–2000); FECM coal subset ~$0.2–0.3B/yr FY2016–2022, declining to ~$0.1B by 2025 | Medium: Coal share of fossil energy R&D estimated from NRC/CRS data; FECM does not publish a coal-only budget line post-2020. Note: EIA narrow definition (Table 5) shows higher coal R&D (FY2016=$363M, FY2022=$280M (2022$)) because EIA includes FECM programs that overlap with CCS (e.g., carbon management, CCUS pilot programs). Dashboard intentionally uses the non-CCS coal subset to avoid double-counting with the CCS stream. EIA's coal R&D figure should not be compared directly to the dashboard value. |
| Oil & Gas | DOE Fossil Energy, Oil and Gas Programs | CRS RS22858; EIA 2023 subsidy report (Table 4: $121M natural gas/petroleum R&D FY2022); DOE FECM budget justifications | FY1979 peak ~$0.5B (real 2024$); FY2022 ~$0.12B. Includes EOR R&D, unconventional gas, gas hydrates (now defunded). Excludes Strategic Petroleum Reserve operations. | Medium: EIA provides technology-level R&D for FY2016–2022; earlier years interpolated from CRS fossil energy share data |
This column combines two distinct types of tax provisions that JCT reports as "tax expenditures." Tax credits (ITC, PTC, §45U, §45Q, §48C, EOR §43) reduce tax liability dollar-for-dollar. A $1M credit costs the government $1M in foregone revenue. Accelerated deductions (IDC expensing, percentage depletion, G&G amortization) allow taxpayers to take deductions earlier or in excess of economic cost. JCT measures these as the present-value timing difference between the accelerated schedule and normal depreciation, not the total deduction amount. This is the same methodology used for the MACRS overlay on renewable energy charts: JCT measures the incremental acceleration benefit, not the full depreciation value. Oil & gas IDC expensing (enacted 1916) and percentage depletion (enacted 1926) are the oldest energy tax provisions in the code. Unlike renewable credits, they have no expiration dates. IDC expensing is highly cyclical, scaling directly with drilling activity and oil prices. The 1982 peak ($10.1B in 2024$) corresponds to 4,500+ active rigs during the drilling boom, while the 1988 trough (near zero) corresponds to the oil price crash. Renewable energy credits scale with installations planned years in advance and exhibit more gradual growth curves.
| Credit / Technology | Source | Key Values | What Is Included | What Is Excluded |
|---|---|---|---|---|
| Solar ITC (§48/§48E) | JCT annual tax expenditure estimates; EIA FY2016–2022 subsidy report (Table A2); Treasury OTA March 2024 | FY2016=$1.58B; FY2017=$2.39B; FY2018=$3.91B; FY2019=$4.48B; FY2020=$7.18B; FY2021=$7.22B; FY2022=$7.77B (EIA Table A4, 2022$×1.05→2024$); FY2024 est.~$18–27B (post-IRA); Treasury OTA: $424.6B ITC+PTC over 2024–2033 | Residential and commercial ITC; Section 1603 cash grants in lieu of ITC (2009–2011); IRA adders (domestic content, energy community, low-income) | State solar ITCs (counted separately under state incentives); MACRS accelerated depreciation (not technology-specific) |
| Wind PTC (§45) | JCT tax expenditure estimates; EIA FY2016–2022 report; CRS wind energy policy reports | FY2013 peak ~$5.8B (with ARRA grants); FY2016=$0.85B; FY2017=$0.82B; FY2018=$2.31B; FY2019=$3.32B; FY2020=$4.16B; FY2021=$3.97B; FY2022=$3.74B (EIA Table A4, 2024$) | Federal PTC at 2.6–2.75¢/kWh; phase-down periods 2017–2019; IRA extension and restoration to full value | Offshore wind ORECs (counted under state mandates); state wind tax exemptions (counted under state incentives) |
| Nuclear §45U | JCT; IRA §45U enacted 2022 (effective tax year 2023) | JCT: $13.1B estimated FY2024–2028; theoretical max ~$11.6B/yr (all U.S. nuclear capacity at $15/MWh) | §45U production credit for existing nuclear ($15/MWh maximum, phases out as electricity price rises above $25/MWh) | Pre-2023 nuclear tax provisions (accelerated depreciation, decommissioning fund deductions) excluded as not technology-specific. EPAct 2005 nuclear PTC (§45J) never triggered because no reactors were built under that provision. |
| CCS §45Q | JCT; EIA FY2016–2022 report; IRA expansion analysis | Pre-2018: $20/tonne storage, $10/tonne EOR. BBA ramp to $50/$35 (superseded by IRA). IRA: $85/tonne storage, $60/tonne utilization, $180/tonne DAC. OBBBA: $85 for all uses (parity). JCT scored IRA §45Q at ~$3.2B/decade while Treasury estimated ~$30B/decade, an order-of-magnitude divergence that reflects uncertainty about deployment pace. | §45Q as enacted through OBBBA (July 2025); includes EOR parity at $85/tonne. Credit subsidy cost of DOE loan guarantees for CCS counted separately under grants. | RGGI and cap-and-trade revenues (indirect; not a direct credit); state carbon pricing adjacency effects. State CCS grants (WY, ND, IL, LA, TX) are not included in the federal series; see State Incentives tab. |
| Battery §48C/§48E | JCT; IRA §48E standalone storage ITC; §48C advanced manufacturing | Pre-IRA: ITC available only for solar-paired storage; §48C manufacturing: $10B IRA allocation. Post-IRA §48E: 30%+ standalone ITC | §48E standalone storage ITC (2023+); §48C advanced manufacturing credit for domestic battery production; co-located solar+storage ITC (pre-2023) | §45X production credits for battery components (manufacturing, not deployment); EV credits (§30D) excluded as transportation policy |
| Geothermal ITC/PTC | JCT; EIA FY2016–2022 report; IRA/OBBBA provisions | §48 ITC for geothermal power since 1978 (10–15%, later 10%, IRA raised to 30% with bonuses). §45 PTC eligibility since EPAct 1992 (up to 2.75¢/kWh). §25D residential GHP credit: 30%. Values small due to limited installed base: ~$250–350M/yr post-IRA. OBBBA extends construction deadline to Jan 1, 2035. | §48 ITC for geothermal power; §45 PTC eligibility (choose one); §25D residential geothermal heat pump credit; §48E/§45Y clean electricity credits (post-2024) | State geothermal incentives (counted separately); exploration risk sharing (DOE loan guarantees for EGS excluded because no such guarantees have been issued) |
| Coal Tax Expenditures | JCT; GAO-22-104637; EIA 2023 subsidy report (Table 2) | Refined coal §45 credit: $8.9B claimed 2010–2020 (~$0.8–1.0B/yr; GAO). Expired Dec 2021. EIA Table A5 annual (2024$): FY2016=$1.09B, FY2017=$1.39B, FY2018=$1.08B, FY2019=$0.71B, FY2020=$0.66B, FY2021=$0.56B, FY2022=$0.62B. Percentage depletion for coal: ~$100–200M/yr (JCT). Coal excise tax (Black Lung): net revenue-raiser, excluded. | Refined coal production credit (§45, expired 2021); excess of percentage over cost depletion for coal; clean coal investment credits (§48A/§48B, ~$2.3B authorized) | Coal excise tax (Black Lung Trust Fund) excluded as a net revenue-raiser. State coal severance taxes also excluded as net revenue-raisers. |
| Oil & Gas Tax Expenditures | GAO RCED-00-301R (FY1977–2000 annual JCT data); JCT pamphlets JCS-1-02 through JCS-1-05 (FY2001–2009); EIA FY2016–2022 (Table A4); CRS IF11528 | Scorecard splits into Tax Credits ($55–90B: percentage depletion excess ~$30–45B, EOR §43 ~$5–10B, non-conventional §29 ~$15–25B) and Tax Acceleration ($45–70B: IDC expensing ~$40–60B, G&G ~$3–5B). GAO peak: FY1982=$10.1B (2024$). EIA net position: FY2016=(-$1.19B), FY2017=(-$1.16B), FY2018=$1.87B, FY2022=$2.18B (all 2024$). | IDC expensing (§263, since 1916); percentage depletion (since 1926, limited to independents since 1975); EOR credit (§43); non-conventional fuels (§29/§45K, mostly expired); G&G amortization (§167); foreign tax credit for royalties (§901) | §199 domestic manufacturing deduction (repealed by TCJA 2017) excluded. MLP treatment (§7704) excluded as midstream, not production-specific. Below-market federal lease rates excluded. State severance tax preferences (~$17B, LOW conf) noted separately in scorecard, excluded from chart rendering. |
This category covers non-R&D direct federal expenditures: demonstration project grants, ARRA cash grants in lieu of tax credits (Section 1603), DOE loan program disbursements, and other direct support. The primary sources are EIA FY2016–2022 (Table A6), DOE USASpending.gov data, and CBO analyses.
| Program | Technologies | Amount | Period | Source |
|---|---|---|---|---|
| Section 1603 Cash Grants (ARRA) | Wind (~$14.7B, 56%), Solar (~$8.4B, 32%), Geothermal, Other | ~$26.2B total disbursed | 2009–2011 | Treasury data; EIA subsidy reports |
| DOE Loan Guarantees (Title XVII/§1705/EIR) | Nuclear (Vogtle $8.3B, Palisades $1.5B); Solar (§1705 12 generation + 4 manufacturing projects $13.3B, Sunwealth $0.29B); Wind (Shepherds Flat $1.3B, Kahuku $0.12B); CCS (Wabash Valley $1.56B); Geothermal (Ormat $0.35B). ATVM automotive loans excluded. | ~$1–3B FCRA cost (~$27B face value) | 2008–2025 | DOE Loan Programs Office / EDF; CRS R42059, R47293 |
| ARRA Clean Energy Demonstration | CCS (FutureGen, regional partnerships), Smart Grid, Solar, Wind | ~$30B total EERE+FE | FY2009–2014 | CBO 2012; EIA 2013 subsidy report |
| IIJA Clean Energy Demonstrations | CCS (4 DAC hubs $3.5B), Battery, Geothermal, Nuclear (advanced) | ~$16B for EERE | FY2022–2031 | CRS E&W Appropriations reports; DOE program pages |
| FutureGen (CCS demo) | CCS only | ~$1B+ | 2003–2015 | DOE; CBO |
Renewable Portfolio Standard (RPS) compliance costs are the above-market payments made by utilities (and ultimately ratepayers) to procure renewable electricity in compliance with state mandates. These are the largest single state-level public support mechanism and are largely absent from federal subsidy inventories.
Primary source: Lawrence Berkeley National Laboratory (LBNL) Historical RPS & CES Target Achievement and Compliance Costs spreadsheet (Barbose et al., August 2025 update). LBNL reports state-by-state compliance costs as a percentage of the average retail electricity bill for 27 RPS states, annually from 2007 to 2024. This report converts these to national dollar totals by multiplying by estimated retail electricity revenue in RPS states (~55–65% of the ~$350–480B U.S. total, varying by year).
Key LBNL findings used in this report: The simple average compliance cost across reporting states rose from 0.9% of the retail bill (2010) to 2.4% (2016) to 4.9% (2024). Dollar-equivalent national totals: ~$1.9B/yr (2010), ~$5.4B/yr (2016), ~$9.0B/yr (2022), ~$14.2B/yr (2024). The sharp post-2020 acceleration reflects both rising RPS targets and the inclusion of CES (clean energy standard) costs in states that have transitioned from RPS to CES frameworks.
Wind vs. solar allocation: LBNL reports total RPS compliance costs by state but does not systematically break out wind-vs-solar nationally. Some states report tier-specific costs (e.g., MA SREC, NJ Class I Solar). This report estimates the national solar/wind split based on these tier-level data and deployment shares: ~55% wind / 35% solar / 10% other in 2010, shifting to ~40% wind / 45% solar / 15% other by 2024. This introduces meaningful uncertainty in the technology-level attribution.
| Type | Technologies | Est. Cumulative | Key Source | Included/Excluded |
|---|---|---|---|---|
| RPS Compliance Costs | Solar (SREC carve-outs); Wind (general RPS procurement) | $100–160B total, 2001–2025 | LBNL Historical RPS & CES Compliance Costs (Barbose et al., August 2025 update); 27 states, 2007–2024 | Included. Above-market cost only, not total contract value |
| TX CREZ Transmission | Wind | ~$7B | PUCT; EIA grid investment data | Partially included in wind grants/infrastructure; note this was ratepayer-funded, not state appropriation |
| Nuclear ZECs | Nuclear (NY, IL, NJ, CT, OH) | $10–18B, 2016–2025 | State utility commissions; individual ZEC proceedings; Calculated from program $/yr rates | Included. Above-market payment to nuclear operators; funded through electricity rates |
| Offshore Wind ORECs | Wind | $3–8B cumulative to date | State PUC OREC proceedings (NY, NJ, MA, CT); BOEM data | Included; though most payments are still prospective. Values reflect contracts executed, not yet fully disbursed |
| Geothermal RPS Carve-outs | Geothermal | $1-3B cumulative (est.) | Rough estimate. LBNL RPS dataset cannot isolate geothermal-specific compliance costs: aggregate RPS cost was at or below wholesale market in many years for geothermal-heavy states, and the two dominant geothermal states (CA, NV) have major data gaps in the LBNL dataset. Values are upper-bound estimates based on geothermal's share (~3-5%) of RPS-qualifying generation. Actual compliance premium may be near zero in years when geothermal was cost-competitive with wholesale. | LOW confidence. Not separately estimable from available data. |
Net metering (NEM) is a utility billing mechanism that credits distributed solar owners for excess electricity at or near the full retail rate (typically $0.25–0.35/kWh). The cost transfer arises because the retail rate includes fixed infrastructure costs (poles, wires, transformers) that solar owners avoid paying when they export power at the retail price but still use the grid for backup. Non-solar ratepayers pay more to cover those fixed costs.
This is distinct from a government expenditure. It does not appear in federal budgets, state budgets, or EIA subsidy inventories. It is a regulatory design choice that redistributes costs among ratepayers. This report includes it because: (1) it is a material public policy intervention that benefits a specific technology; (2) the scale is comparable to or larger than many programs that are counted; and (3) structural analogues (Price-Anderson for nuclear, RPS for wind) are included.
| Source | Method | Finding | Use in This Report |
|---|---|---|---|
| LBNL / Brattle (Oct 2025) | Econometric analysis of state electricity price changes; controlled for fuel mix, demand, infrastructure | 5pp increase in net-metered solar penetration associated with +1.1¢/kWh nationally | Primary quantitative anchor for national cost transfer estimate |
| CPUC Public Advocates Office (2024) | California-specific rate analysis: fixed cost shortfall from NEM 1.0/2.0 participants | CA cost shift grew from $3.4B/yr (2021) to $8.5B/yr (2024); ~21–27% of non-solar CA bills | California anchor point; CA = ~40–50% of national NEM total |
| Verdant Associates (2021) | CA NEM 2.0 unreformed 20-year cost projection for CPUC NEM 3.0 proceeding | Cumulative CA cost shift ~$13B if unreformed over 20 years (~$650M/yr avg) | Pre-NEM 3.0 baseline; confirms CPUC methodology |
| NREL (2025) | National household-level analysis at current (2024) penetration rates | <$1/month per non-solar ratepayer nationally at current penetration | Lower bound; per-household metric understates total when scaled across millions of non-solar households |
Method: Apply the LBNL/Brattle penetration-price elasticity (+1.1¢/kWh per 5pp NEM penetration) to historical annual NEM deployment data. Multiply implied price premium by non-solar electricity consumption. CA is modeled separately using the CPUC anchor points ($0–0.5B/yr 1995–2010, rising to $3.4B/yr by 2021, $8.5B/yr by 2024, then declining post-NEM 3.0). National = CA estimate + 2–3x multiplier for other states (CA has ~40–50% of national NEM capacity).
Why the range is wide: (1) Disputed causation — studies disagree on whether NEM penetration is the cause of price increases vs. correlated factors; (2) Value-of-solar offset — solar advocates argue distributed solar provides grid services (peak reduction, T&D deferral, avoided emissions) worth $0.06–0.14/kWh, potentially exceeding the retail rate credit; (3) Pre-2015 data is thin; most NEM growth occurred after 2010.
What is excluded: NEM+storage cost transfers are counted in the battery storage state stream, not here. Commercial NEM (non-residential) is included in the estimate. Community solar cost transfers are not separately quantified.
Study-by-study evidence: LBNL (2017): ±5% price impact at 10% solar penetration. LBNL/Brattle (2025): +1.1¢/kWh per 5pp NEM penetration nationally; CA NEM contributed up to 2¢/kWh. CPUC Public Advocates (2024): CA cost shift $8.5B/yr, ~21–27% of non-solar CA bills. Verdant (2021): CA NEM 2.0 unreformed → $13B over 20 years, driving NEM 3.0 reform. NREL (2025): <$1/month impact per non-solar ratepayer nationally at current penetration.
This category covers state-level programs outside of RPS compliance that provide direct financial benefit to specific technologies. Like RPS compliance costs, most of these are ratepayer-funded rather than government-appropriated.
| Program / Type | Technology | Calculation Method | Cumulative Estimate | Source Quality |
|---|---|---|---|---|
| Zero Emission Credits (ZECs) | Nuclear | Annual $/yr program rate × years active: NY ~$462M/yr (2016+); IL ~$235M/yr (2017+); NJ ~$300M/yr (2019+); CT ~$200M/yr (2019+); OH $150M/yr (2019–2022) | $10–18B (2016–2025) | High: program rates from state PUC orders; date ranges from enacted legislation |
| Palisades Restart (MI) | Nuclear | MI state appropriation ~$300M (enacted); DOE Title XVII loan guarantee ~$1.5B (announced 2024) | ~$1.8B | High: specific program with published amounts. Note: DOE loan guarantee = FCRA credit subsidy cost used (~6% of face value) |
| CA SGIP (Battery) | Battery Storage | CPUC annual SGIP program disbursements; program total through 2025. Morgan Lewis (2026) confirms $280M most recent allocation | ~$1.5B+ (2001–2025) | High: CPUC public program data |
| State Battery Procurement Mandates | Battery Storage | Morgan Lewis (2026) documents 13 states with procurement targets. Cost transfer estimated from ratepayer-funded contracts above market. Morgan Lewis: ~40 GW by end-2026 U.S. installed; ~80–85% in CA and TX | $3–8B est. (2020–2025) | Medium: mandate GW targets are well-sourced; dollar cost of above-market contracts requires per-state rate case analysis not fully available |
| State Solar ITCs / Rebates | Solar | Key programs: NC 35% ITC (2007–2015, ~$800M–1.2B total); CA CSI (2006–2013, ~$2B); MA SMART (~$200M/yr); NY-Sun ($1B+ committed). State budget documents + program reports | $5–10B est. | Medium: major programs well-sourced; smaller state programs not fully catalogued |
| MD Geothermal RPS Carve-out | Geothermal | MD PSC enacted $94.47/MWh geothermal tier (2022). Small installed base limits total cost transfer. Estimate based on contracted capacity × $/MWh premium above market | <$0.5B to date | High for program terms; low for utilization (minimal capacity deployed) |
Property tax exemptions are excluded from all technology totals due to the absence of a national aggregate series. The table below documents the largest identified programs and their estimated magnitudes where available. Sources: state tax expenditure reports, AWEA/ACP market reports, LBNL Tracking the Sun, DSIRE database.
| State | Technology | Program Description | Est. Value | Source |
|---|---|---|---|---|
| TX | Wind | Chapter 313 (TEVA, expired 2022): school district property tax value limitations for wind projects. Chapter 312: county/city abatements (ongoing). Enabled most West Texas wind development. | ~$1.5B (Ch. 313 through 2022) | AWEA/ACP estimates; TX Comptroller |
| IA | Wind | Full property tax replacement: wind turbines assessed at $0/acre for 5 years, then partial assessment via Iowa Code §427B.26. IA has ~12.4 GW installed wind (2024). | $200–500M est. | IA Dept. of Revenue tax expenditure report |
| KS, MN, OK, SD, ND | Wind | Various property tax exemptions, abatements, and payment-in-lieu-of-taxes (PILOT) agreements. KS exempts wind for 10 years. MN provides production tax alternative. OK provides 5-year ad valorem exemption. | $500M–1.5B combined est. | DSIRE; state tax expenditure reports |
| CA, NY, NJ, MA | Solar | Solar property tax exclusions: CA (Prop 7/Revenue and Taxation Code §73), NY (Real Property Tax Law §487), NJ (exemption from property tax assessment), MA (20-year exemption). LBNL (2021): exemptions save $0.5–1.5¢/kWh in many states. | $2–5B combined est. | LBNL Tracking the Sun; state statute analysis |
| CO, AZ, OR, CT + 30 others | Solar | ~36 states total exempt solar from property tax assessment. Most are full exclusions: solar equipment is not counted in assessed value. At ~5M cumulative residential installations × ~$20K avg system × ~1% effective property tax rate × avg 15-yr benefit, residential solar alone = $3–6B. | $3–6B residential est. | DSIRE; Back-of-envelope estimate from installation data |
| Various | Nuclear | Treatment varies widely. Large plants (30–50% of county assessed value) negotiate PILOT agreements. Some states use production-value assessment (far below capital cost). No systematic national accounting exists. | Not quantified | Plant-by-plant analysis required |
| NV, UT, ID | Geothermal | NV property tax abatement for renewable energy. UT, ID limited exemptions. Small installed base limits magnitude. | <$200M est. | DSIRE; NV Governor's Office of Energy |
CCS state support was removed from chart data in for insufficient sourcing. This table documents identified state programs. No defensible aggregate annual series exists.
| State | Program / Mechanism | Status | Est. Value | Source Quality |
|---|---|---|---|---|
| WY | CCS severance tax exemption: CO₂ stored in WY geological formations exempted from severance tax. WY also enacted primacy for Class VI UIC wells (2020) and long-term liability transfer framework (2021). Wyoming Energy Authority CCS grants. | Active | $50–200M est. | Medium: program terms well-documented; dollar flows not publicly reported |
| ND | CO₂ storage trust fund (HB 1030, 2009). Long-term liability transfer to state after 10 years post-injection. ND Industrial Commission CCS project grants. Lignite Vision 21 CCS project support. | Active | $100–300M est. | Medium: Lignite Vision 21 costs partially documented |
| TX | HB 1796 (2009): offshore CO₂ storage liability framework. Railroad Commission Class VI primacy (applied 2023). Severance tax exemptions for CO₂-EOR operations (existing, non-CCS-specific). TX GLO offshore storage leasing program. | Active | $50–150M est. (EOR exemptions) | Low: EOR severance exemptions are industry-wide, not CCS-specific; attribution uncertain |
| LA | Act 517 (2009): Class VI permitting framework. Act 349 (2023): updated storage liability. LA DNR mineral resources permitting. Industrial Tax Exemption Program (ITEP) applies to CCS-equipped facilities. | Active | $50–100M est. | Low: ITEP is general industrial, not CCS-specific |
| IL | Carbon Dioxide Transportation and Sequestration Act (2011). Decatur ADM/IBDP project state support. IL EPA permitting framework. | Active | $20–50M est. | Medium: Decatur project costs documented |
| CA/RGGI states | Carbon pricing adjacency: CA Cap-and-Trade and RGGI create a carbon price ($25–35/tonne) that implicitly supports CCS economics. CARB CCS protocol (2018) allows CCS credits under compliance market. No direct state grants to CCS. | Indirect | Not quantified | High for program terms; impossible to attribute a dollar value to the implicit CCS support from carbon pricing without project-specific analysis |
Total identified CCS state support: $0.3–0.8B (direct grants and exemptions), plus indirect carbon pricing adjacency that is not quantifiable as a dollar subsidy. This is materially below state-level support for any other technology except coal. The CCS state support chart stream remains excluded pending better dollar-level sourcing from state agencies.
LIHEAP (~$185B): Low Income Home Energy Assistance Program. Congressional block grant appropriations to states for heating/cooling bill assistance. Technology-neutral — subsidizes energy bills regardless of fuel source (60% natural gas, 25% electric, 10% oil, 5% propane nationally). Included because it is the single largest federal energy appropriation by cumulative spending and is tracked by EIA as an energy subsidy. Primary source: CRS RL31865 Table 1 (FY1981–2018), which provides exact annual funding levels; extended with LIHEAP Clearinghouse release data (FY2019–2026). LIEAP predecessor (FY1980) is included at $3.76B (2024$). Key anchor values: FY1981 $5.30B, FY1982 $5.11B, FY1996 $1.63B (Reagan-era low), FY2009 $7.15B (ARRA), FY2021 $9.35B (ARP supplemental), FY2025 $4.02B. HIGH confidence. A toggle on the Overview tab allows users to include or exclude LIHEAP from the dashboard totals because of its technology-neutral character.
Weatherization Assistance Program (~$26B): DOE-administered since 1976. Provides grants to states for whole-home weatherization of low-income dwellings. Base funding ~$0.2–0.3B/yr. Two large spikes: ARRA $5.0B (FY2009, a 20× increase) and IIJA $3.5B (FY2022). Source: DOE EERE budget justifications, USASpending.gov CFDA 81.042, IIJA P.L. 117-58. HIGH confidence for spike years; base years use DOE program history estimates.
DOE Efficiency R&D (~$49B): Building Technologies Office (BTO), Advanced Manufacturing Office (AMO), and Federal Energy Management Program (FEMP). Excludes all EERE renewable technology offices (solar, wind, geothermal, bioenergy, water power, hydrogen — each in their own technology). Source: IEA Energy Technology RD&D database "Energy Efficiency" category (FY1974–2016), DOE EERE budget justifications (FY2017–2025). Carter-era peak ~$2.5B/yr (2024$). Reagan cuts to ~$0.5B/yr. Steady recovery since. CRS RS22858 reports efficiency = 16% of total DOE energy R&D historically, which cross-validates the cumulative. HIGH confidence. Note: IEA "Energy Efficiency" may include some Vehicle Technologies Office (VTO) spending that overlaps with transportation R&D; this potential double-count is small relative to total.
Efficiency Tax Credits (~$37B): §25C (residential energy property credit, now Energy Efficient Home Improvement Credit), §179D (commercial building energy efficiency deduction), §45L (new energy efficient home credit). Excludes §25D solar ITC to avoid double-counting with the solar technology. Pre-EPAct 2005: Carter-era residential energy credit (small, ~$0.4B/yr 2024$ in 1978–1982). EPAct 2005 created §179D and expanded §25C. ARRA expanded §25C to $1,500/taxpayer (FY2010 peak $4.4B 2024$). IRA expanded §25C to $3,200/yr for heat pumps + $1,200/yr other measures; made §179D permanent. Source: EIA subsidy reports "Conservation" tax expenditure row (FY2007–2022), JCT estimates. Pre-2005 data is the weakest component. MID confidence.
Utility Ratepayer Efficiency Programs (~$189B): State utility commissions require utilities to fund demand-side management (DSM) programs through ratepayer surcharges. Structurally identical to RPS: state mandates that shift costs to ratepayers through utility rates, with no government budget impact. 26 states + DC have Energy Efficiency Resource Standards (EERS). Sources: ACEEE State Energy Efficiency Scorecard (annual, published since ~2007), CEE Annual Industry Report, EIA Form 861 (utility DSM costs and savings). Growth: ~$1B/yr in 1990 → $3.5B by 2000 → $7–8B by 2015–2020. MID confidence — no single authoritative source publishes a complete national year-by-year total. The post-2007 trajectory is well-anchored by ACEEE; the 1990–2006 period relies on EIA Form 861 data and industry reports. This is the weakest large stream in the dashboard by dollar-weighted confidence.
State Clean Energy Fund Surcharges (~$53B): Per-kWh ratepayer surcharges collected by states to fund clean energy programs (MID confidence). Three-state validation: NYSERDA (NY) spent $3.4B through 2023 from $7.5B authorized 2016-2032 (NY Comptroller Aug 2024); NJ BPU Clean Energy Program collects ~$345M/yr in new ratepayer funding (FY2026 budget); CT Green Bank deploys ~$10-15M/yr in subsidies (2016-2025 annual reports). These three states (~10% of US population) account for ~$12-15B cumulative, implying a national total of $50-60B, consistent with our $53B estimate. Pre-CEF programs include NY System Benefits Charge (~$175M/yr 1998-2015), CA Public Goods Charge (~$200-300M/yr), MA Renewable Energy Trust, OR Energy Trust (~$150-200M/yr), and ~15 other state programs. Surcharges fund a mix of renewables, efficiency, and clean energy R&D. Distinct from utility ratepayer efficiency programs (ACEEE stream): state clean energy funds are administered by state agencies or green banks, while utility EE programs are administered by utilities under EERS mandates. Some states bundle both under a single surcharge, creating potential overlap; where identifiable, the efficiency portion is excluded from this stream
DOE Grid R&D (~$15B): Office of Electricity (OE) plus grid modernization initiatives. Includes smart grid R&D, grid-scale energy storage R&D, transmission planning, grid resilience research, power electronics, and superconductivity programs. Excludes battery storage R&D (which is in the Battery technology). Sources: IEA Energy Technology RD&D database "Electricity Transmission & Distribution" and "Energy Storage" categories (FY1974–2016), DOE OE budget justifications (FY2017–2025), CRS RS22858 (electric systems = 6% of DOE energy R&D). Steady at ~$0.2–0.4B/yr over the entire 50-year period. HIGH confidence.
Federal Grid Grants (~$12B): Two major programs dominate. ARRA Smart Grid Investment Grants ($3.4B) and Smart Grid Demonstrations ($0.6B) funded 99 projects in 49 states (FY2009–2013), including AMI, distribution automation, and synchrophasors. IIJA (P.L. 117-58 §§40101–40107) created: Grid Resilience and Innovation Partnerships (GRIP) at $2.5B, Transmission Facilitation Program at $2.5B (revolving fund), State-Based Grid Deployment at $3.0B, and tribal electrification at $0.5B. Sources: DOE Grid Deployment Office, USASpending.gov. The gap period (FY2014–2021) has minimal grid-specific federal grant activity (~$0.05B/yr). HIGH confidence for ARRA and IIJA program totals; year-by-year obligation patterns estimated from DOE disbursement reports.
Design decision — ratepayer-funded transmission excluded: This technology category captures only federal budget expenditures on grid infrastructure. It excludes ratepayer-funded regional transmission projects including Texas CREZ (~$7B, ERCOT ratepayer-funded), MISO Multi-Value Projects (~$7B), and MISO Long Range Transmission Plan (~$20B authorized). These are conceptually analogous to RPS compliance costs (state-mandated, ratepayer-funded) and could be classified as Regulatory Cost Transfers. They are excluded because (1) the beneficiary attribution is mixed (transmission serves all generators, not a single technology), (2) cost allocation methodologies differ across RTOs, and (3) including them would require consistent treatment of all grid upgrade costs nationally, which no existing data source supports. This exclusion is documented in the "What Is Not Included" section.
| Excluded Item | Relevance | Reason for Exclusion |
|---|---|---|
| Price-Anderson Act (Nuclear) | Caps nuclear operator liability at ~$13.5B; estimated full liability could be $100B+. GAO, CBO, and independent analysts treat this as a substantial implicit subsidy. | No identifiable federal budget impact. EIA explicitly excludes it. The cost transfer is contingent on an accident occurring — in expectation, the value depends on probability assumptions that are highly disputed. Including it could add $5–50B to the nuclear cumulative total depending on assumptions. Users should be aware this is excluded. |
| Nuclear Waste Fund (DOE) | ~$43B in the fund (ratepayer-funded at 0.1¢/kWh since 1983); permanent repository never built despite decades of collections. | Ratepayer-funded; not a public expenditure. The unresolved repository situation represents a federal obligation not fully discharged — arguably a future public cost. Not quantified here. |
| Federal Power Marketing Administrations (Hydro) | BPA, WAPA, SWPA provide below-market federal hydropower. EIA 2008 estimated ~$2B/yr in interest rate support. | NOW INCLUDED (v18). PMA below-market electricity is captured in the Hydropower technology as a Regulatory Cost Transfer (~$8B cumulative at ~$0.15B/yr). The $2B/yr EIA estimate uses a different methodology (interest rate subsidy on federal capital); our estimate uses the retail-wholesale price differential approach, which produces a lower but more conservative figure. |
| Military / DOD nuclear programs | Naval nuclear propulsion R&D (DOD/Navy) and weapons programs (NNSA) drove significant nuclear technology development that benefited civilian nuclear. | Defense programs have no civilian market application as a primary purpose; attribution to commercial nuclear R&D would require non-standard assumptions. NNSA weapons budget exceeds $20B/yr — including any fraction would substantially alter the nuclear R&D estimate. |
| General tax provisions (MACRS, bonus depreciation) | Accelerated depreciation benefits all capital-intensive industries including energy. | Not technology-specific; benefits all capital investments. EIA explicitly excludes these from its energy subsidy definition. Including them on a pro-rata basis would add substantially to all technologies. |
| EV tax credits (§30D, §45W) | Indirectly benefits battery storage through manufacturing scale and cost reduction. | Transportation policy, not energy storage policy. Attribution to grid storage would require cost-allocation assumptions. |
| State and local property tax abatements and exemptions |
Wind: TX Chapter 312/313 abatements (largest program nationally; enabled most West Texas wind development); IA full property tax exemption on wind turbines; MN, KS, OK, SD, ND exemptions. AWEA estimated TX Chapter 313 alone provided ~$1.5B in abatements to wind projects through its 2022 expiration. Solar: ~36 states exempt solar installations from property tax assessment. Major states include CA, NY, NJ, MA, CO, AZ. Lawrence Berkeley (2021) found state solar property tax exemptions saved solar owners $0.5–1.5¢/kWh in many states, implying meaningful cumulative value at current installed base. Nuclear: Treatment varies widely by state. Some states tax at full assessed value; others use production-value assessment (far lower given capital intensity); others have negotiated payment-in-lieu-of-taxes (PILOT) agreements. Large nuclear plants can represent 30–50% of a county's assessed value, making the abatement terms consequential. Battery/CCS/Geothermal: Property tax exemptions exist in some states for storage and geothermal; not systematically catalogued at dollar scale. |
Why excluded from all technology totals: No single national database tracks actual abatement dollar values by technology at the project or state level. DSIRE (Database of State Incentives for Renewables and Efficiency) catalogs program existence and terms but does not report aggregate expenditure values. Individual state analyses exist — AWEA/ACP for wind, LBNL for solar — but use different methodologies and coverage periods that cannot be directly summed into a cross-technology comparable series. The asymmetry this creates: Wind and solar likely benefit most in absolute dollar terms from property tax exemptions given their large installed bases and broad state coverage. Nuclear may benefit most on a per-plant basis given asset values. CCS, battery storage, and geothermal have limited coverage. Excluding abatements therefore creates a mild undercount that is not uniform across technologies — it disproportionately understates wind and solar state support relative to CCS and geothermal. Future inclusion: A rigorous abatement analysis would require compiling county assessor records, PILOT agreements, and state tax expenditure reports for each major project in each state. This is a tractable research project but beyond the scope of the current report. It will be incorporated in a future edition. |
| Community solar cost transfers | Community solar subscribers typically receive credits at above-wholesale rates. | Methodology for estimating cross-subsidy value not established; programs vary significantly by state. Not included in NEM estimate. |
This report does not capture all forms of public support for energy technologies. The following material categories are excluded or only partially captured, with approximate magnitudes where estimable. Transparency about what is not included is as important as what is.
| Exclusion | Technologies Affected | Est. Magnitude | Reason for Exclusion |
|---|---|---|---|
| MACRS 5-Year Accelerated Depreciation | Solar, Wind, Battery, Geothermal, CCS (5-yr recovery vs. 20-30 yr economic life) | $0.3B/yr (JCT); cumulative $5–8B (all energy) | revised to JCT incremental measure. JCT JCX-97-14 reports 5-yr MACRS for solar/wind/etc at ~$0.3B/yr corporate (FY2014–2018). JCT JCX-55-16 shows de minimis (<$0.25B/yr) for FY2017–2021. used a CBO-based model that showed $3–5.5B/yr — this was 10–15× higher because CBO measures the total present-value of all depreciation deductions while JCT measures the incremental cost of 5-yr vs. default MACRS class. Since all other tax streams in this report use the JCT tax expenditure methodology, the MACRS overlay now matches. Approximate cumulative: solar $2–4B, wind $1–3B, battery+geothermal <$1B. Still excluded from scorecard totals. OBBBA (2025) removes 5-yr MACRS for solar/wind with BOC after 12/31/2024 but restores 100% bonus depreciation permanently. |
| Section 1603 Cash Grants (reconciled) | Wind ($13.0B nom, 49.6%), Solar ($10.3B nom, 39.2%), Geothermal ($0.8B, 2.9%), Other ($2.2B, 8.3%) | $26.16B total (Treasury project data) | Fully reconciled using Treasury project-level awards dataset (Website-Awarded-as-of-3_1_18.xlsx, 10,012 awards). Technology shares differ from Treasury's cited 56%/32% split; actual data shows Wind=49.6%, Solar=39.2%. Key timing finding: wind awards heavily front-loaded (FY2009–2013), solar awards back-loaded (peaking FY2014). All §1603 chart streams now sourced directly from this dataset rather than EIA "direct expenditure" proxies. No gap remains. |
| State Property Tax Exemptions | Solar (36 states), Wind (IA, TX, KS, MN, OK, others), Geothermal (select) | $5-20B cumulative (all technologies) | No aggregate annual series exists. 36 states exempt solar from property tax; IA exempts wind for 5-10 years; TX Ch. 312 wind abatements est. $200-500M cumulative. This is the single largest identified data gap in the analysis. |
| State Sales Tax Exemptions | Solar (25 states), Wind (IA, MN, CO, others), Geothermal (select) | $2-8B cumulative | 25 states exempt solar equipment; several exempt wind. On a $20K residential system at ~6% sales tax, the exemption is ~$1,200. At ~5M cumulative U.S. residential installations, residential solar alone may represent $3-6B. No aggregate annual series exists. |
| DOE LPO Portfolio (non-nuclear) | Solar mfg. (First Solar), Battery mfg. (Ford BlueOval $9.2B, Ultium $2.5B), Clean vehicles, Grid | $40B+ committed post-IRA | Only nuclear loans (Vogtle $8.3B, Palisades $1.5B) are tracked in this report. The broader LPO portfolio includes ATVM loans for EV/battery manufacturing plants ($15B+) and Title XVII loans for solar and clean energy manufacturing. Excluded because credit subsidy costs (the FCRA credit subsidy cost, typically 3–10% of face value) are not publicly disaggregated by technology. |
| Section 45X Mfg. PTC | Solar cells/modules, Battery cells/modules, Wind components, Inverters, Critical minerals | $30.6B over 2023-2032 (JCT); Goldman Sachs est. $80B+ | Manufacturing production credit — per-unit payments for domestic production (solar cells $0.04/W, modules $0.07/W, battery cells $35/kWh, inverters $0.02–0.11/W). This is manufacturing policy rather than deployment policy, subsidizing production capacity rather than installation. IRS has not yet reported claims by technology, so allocation to individual technology streams is not possible. OBBBA (2025) modified eligibility: reduced or eliminated credits for some components, added FEOC (Foreign Entity of Concern) restrictions. Magnitude rivals several included categories and will grow as domestic manufacturing scales. |
| EV Credits (section 30D/45W) | Battery (indirectly: EV demand drives battery cost reduction) | $50-100B+ over 2023-2032 | Transportation policy, not energy generation. OBBBA terminated consumer EV credits after Sept. 30, 2025. However, EV credits are the largest single driver of battery technology cost reduction. |
| CCS State Grants and EOR Exemptions | CCS | $0.5-2B (indirect) | Previously included as a chart stream; removed for insufficient sourcing. See State Incentives tab. |
| Below-Market Federal Lease Rates | Oil & Gas (onshore federal lands) | $43B cumulative (1975–2025) | NOW INCLUDED (v18). Added as "Below-Market Federal Leasing" stream in O&G, classified as Regulatory Cost Transfer. Methodology: ONRR onshore O&G royalties × (16.67% − 12.5%) / 12.5%. Benchmark is the 16.67% IRA rate (comparable to state rates in UT, ND, CO, NM). Validated at $1.6B/yr average (2015–2024) against TCS benchmark of $1.5B/yr. Peak $2.65B in FY2022 (oil price spike + record Permian production). CBO finds raising the onshore rate to 18.75% would have "negligible" impact on production. The prior methodological asymmetry with NEM has been resolved: both NEM (solar) and below-market leasing (O&G) are now included as Regulatory Cost Transfers. |
| Nuclear Decommissioning Fund Tax Benefits | Nuclear | $1-3B cumulative | Tax-deductible contributions to qualified decommissioning funds (section 468A). Modest magnitude; reflects deferred tax liability rather than direct public funding. |
All values are expressed in real 2024 U.S. dollars. Nominal historical values are converted using the GDP implicit price deflator from OMB Historical Tables (Table 10.1), consistent with the deflator used in CRS RS22858. The GDP deflator is preferred over CPI for government spending comparisons because it better reflects the prices of goods and services government programs actually purchase.
Important caveats: (1) Energy equipment prices have fallen substantially — solar module costs declined 99%+ since 1977 in real terms. Expressing early solar R&D in 2024 dollars creates apparent parity with modern dollar amounts, though the purchasing power for actual hardware differed substantially. (2) For tax credits, the nominal value of foregone revenue is reported as stated by JCT/Treasury; inflation-adjusting these is less meaningful because they represent current-year revenue impacts.