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 CMM synthesis. Hover for year-by-year breakdown.
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.
Annual flows estimated from: (1) CRS RS22858 decade-by-decade DOE R&D allocation; (2) EIA Federal Public Funding Reports FY2016/2019/2022; (3) JCT tax expenditure estimates for ITC, PTC, §45U, §45Q; (4) LBNL RPS Status Report compliance cost series; (5) CPUC/LBNL net metering cross-funding data. Pre-1990 values for solar, wind, and geothermal carry higher uncertainty. All values are approximate annual mid-estimates, illustrative of order-of-magnitude and trend.
This report is retrospective: chart data ends at the last year with actual or enacted data for each stream. Tax credit streams generally end at 2022 (last year with JCT/EIA actuals); R&D appropriations extend through enacted FY2024–2025 budgets and include IIJA supplemental appropriations where applicable (wind, solar, geothermal FY2022+). CCS R&D values represent estimated CCS-specific subset of the broader FECM budget. CCS State/RGGI and Battery NEM+Storage streams removed from prior versions (insufficient sourcing).
Net metering is a ratepayer cost transfer: not a government expenditure: excluded from EIA federal inventories. Included here as a state policy instrument with measurable distributional effects.
| Technology | R&D | Tax Credits | Grants/DOE | Loan Guar. | RPS/State | Net Metering † | ZECs/Mandates | Total |
|---|---|---|---|---|---|---|---|---|
| Nuclear | $85–95B | $2–3B | $10–15B | $8–12B | $15–25B | N/A | $10–18B | ~$158–205B |
| Solar | $12–18B | $85–110B | $15–25B | $3–6B | $45–70B | $30–65B | $5–10B | ~$195–310B |
| Wind | $8–14B | $50–70B | $5–10B | $2–4B | $35–55B | $1–3B | $2–4B | ~$103–160B |
| CCS | $10–18B | $3–8B | $3–6B | $1–3B | Not quantified ‡ | N/A | $1–3B | ~$18–38B |
| Battery | $3–6B | $8–15B | $4–8B | $0.5–2B | $2–5B | N/A | $2–5B | ~$19–41B |
| Geothermal | $4–6B | $4–8B | $1–2B | <$0.5B | $3–6B | N/A | $1–3B | ~$13–26B |
† Net metering: retail-rate cost transfer from non-solar to solar ratepayers. Not a government expenditure. CMM estimate: $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 Net Metering tab.
‡ CCS state support: WY, IL, ND, TX, LA have enacted CCS-adjacent grants, severance tax exemptions for CO₂-EOR, and storage liability frameworks. RGGI and CA Cap-and-Trade create indirect carbon pricing adjacency. No defensible aggregate annual series exists; prior versions of this dashboard included a modeled $0.5–2B estimate that has been removed pending better sourcing.
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: $4.7B/yr national RPS compliance by 2018. | $45–70B | 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 | NC 35% ITC (2007–15, $800M–1.2B). MA SMART ~$200M/yr. NY-Sun $1B+. CA CSI ~$2B total. | $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. TX CREZ transmission build-out: ~$7B ratepayer-funded for wind. | $35–55B | 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.
Net metering and Price-Anderson are structurally similar: both shift costs from technology adopters to third parties, both are excluded from standard federal public funding inventories, and both can flip technology rankings when included.
CMM Research Note · 2025NEM allows solar owners to receive credits for excess electricity at or near the full retail rate (~$0.25–0.35/kWh). The public funding value is the gap between that credit and the actual wholesale avoided cost (~$0.05–0.08/kWh), recovered from non-solar ratepayers through utility rate design. This transfer does not appear in government budgets: which is why EIA excludes it from its federal public funding inventories.
Contested: Solar advocates argue value-of-solar analyses (grid deferral, avoided T&D, carbon avoidance) often equal or exceed the retail rate credit. Critics note the cost shift is regressive: it benefits wealthier solar adopters at the expense of renters and lower-income ratepayers.
| Category | EIA FY2022 Report EIA | This Report CMM | Difference and Reason |
|---|---|---|---|
| Nuclear (total FY2022) | $390M — tax provisions + limited direct R&D to non-federal recipients | ~$1.7B — full DOE-NE appropriation + ZEC ratepayer transfers | EIA excludes R&D to federal labs and state ZECs (not federal programs). CMM includes full DOE-NE budget authority and state ZEC programs. |
| Solar (total FY2022) | $7.5B — ITC tax expenditure + direct expenditures | ~$12–14B — ITC + SETO R&D + RPS share + NEM | EIA excludes state RPS compliance costs (state programs) and NEM (no federal budget impact). CMM adds both. |
| Wind (total FY2022) | $3.6B — PTC tax expenditure + limited direct | ~$6–7B — PTC + WTO R&D + RPS compliance share | EIA excludes state RPS compliance costs. CMM adds the wind share of national RPS compliance (~$2–2.5B/yr by 2022). |
| RPS Compliance (all) | $0 — explicitly excluded as state program | ~$4.7B/yr by 2018; $80–130B cumulative 2001–2025 | This single omission accounts for the largest gap between EIA and CMM totals. RPS compliance is funded by ratepayers under state mandate — real public cost, no federal budget impact. |
| Net Metering | $0 — excluded (no federal budget impact) | $20–50B cumulative (CMM est.) | Ratepayer cost transfer. EIA excludes by definition. CMM includes as structurally analogous to other ratepayer-funded state programs. |
| Total FY2022 (all energy) | ~$18B (EIA FY2022 total, in-scope) | Estimated ~$35–45B/yr using CMM definition | The ~2x gap is almost entirely explained by RPS compliance costs and NEM transfers, both of which are real ratepayer costs excluded from EIA's federal-budget-only definition. |
| 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 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 Status Reports | State RPS compliance costs, 2001–2024 | $4.7B/yr by 2018; roughly half of all U.S. RE growth linked to RPS |
| 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 |
This report estimates cumulative U.S. federal and state public financial support for six energy technologies 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 and interpolated between them — they are not year-by-year audit-quality data.
The report uses a broad definition of public funding that includes: direct federal appropriations (R&D), tax expenditures (credits, deductions), direct grants and loan guarantees, state regulatory compliance costs, and ratepayer cost transfers. This is 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.
| 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 |
| Solar | Solar Energy Technologies Office (SETO) | DOE SETO FOA announcements; DOE FY2025 Budget in Brief; CRS RS22858 | FY2019=$130M; FY2020=$125M; FY2021~$128M; FY2023~$280–360M; 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 | FY2016=$95.5M; FY2017=$90M; FY2018=$92M; FY2019=$92M; FY2020=$104M; FY2021=$110M; FY2022=$114M | 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 ~$450–550M/yr (60–75% of FECM total, excluding methane, critical minerals, hydrogen, NETL operations) | Medium-High: FECM budget mixes CCS with other fossil/carbon programs; CCS-specific subset is a CMM estimate. 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 | FY2016=$70M; FY2017=$84M; FY2018=$105M; FY2019=$105M; FY2020=$148M; FY2021=$150M; FY2022=$162M; FY2025=$488M (IIJA-inflated) | Low FY2013+; Note: FY2025 figure unusually high due to IIJA supplemental appropriations |
| 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~$2.2B; FY2022=$7.5B (EIA); 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=$1.3B (EIA); FY2019~$4.0B; FY2022~$3.5B | 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 — no reactors 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; Treasury estimated ~$30B/decade — order-of-magnitude divergence 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) not included in 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 — no such guarantees yet issued) |
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) | Nuclear (Vogtle ~$8.3B; Palisades ~$1.5B); Solar (SunPower, First Solar, Solyndra); Wind (offshore) | ~$16B+ committed | 2008–2025 | DOE Loan Programs Office; EIA 2023 report; CRS 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) Renewable Portfolio Standards Annual Status Report (published annually). LBNL calculates total above-market cost as the difference between the contract price paid for renewable energy and the applicable avoided-cost or wholesale market benchmark. For SREC (solar renewable energy credit) markets, the compliance cost includes SREC prices paid at auction or bilaterally.
Key LBNL findings used in this report: Total national RPS compliance cost reached $4.7B/yr by FY2018. Solar SREC carve-outs (NJ, MA, DC, MD, CT) have carried prices of $200–450/MWh, generating the majority of SREC market value. Roughly half of all U.S. renewable energy growth 2000–2020 is attributable to RPS policies.
Wind vs. solar allocation: LBNL reports total RPS compliance costs, not wind-vs.-solar splits for every year. The solar and wind RPS shares in the charts are CMM estimates based on renewable procurement shares by year from LBNL deployment data. This introduces meaningful uncertainty particularly before 2015.
| Type | Technologies | Est. Cumulative | Key Source | Included/Excluded |
|---|---|---|---|---|
| RPS Compliance Costs | Solar (SREC carve-outs); Wind (general RPS procurement) | $80–130B total, 2001–2025 | LBNL RPS Status Reports (annual); LBNL Barbose et al. 2019 | 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; CMM calculation 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 | MD PSC (MD RPS carve-out $94.47/MWh enacted 2022); NV, AZ state utility filings | Included; thin sourcing. Cumulative total modest given small installed base |
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 not 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. CMM 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 | CMM Use |
|---|---|---|---|
| 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.
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 = credit subsidy cost ~$460M, not $1.5B 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) |
| 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. | Hydropower is not one of the six technologies covered by this report. |
| 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 dramatically skew 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 dramatically 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) | $5-15B/yr (all energy); cumulative $50-150B+ | MACRS (est. 1986) is a general business tax provision, not energy-specific. Treasury classifies it as part of the reference tax law baseline, meaning it is not a "tax expenditure" under that definition. The 5-yr recovery period for renewables (vs. 20-30 yr economic life) provides material benefit. CBO includes MACRS in wind/solar analyses. Excluded because no technology-specific annual series exists; benefit is entangled with bonus depreciation (100% under TCJA through 2022, phasing to 40% in 2025). If included, would increase solar and wind cumulative totals by roughly 15-25%. |
| Section 1603 Cash Grants (allocation gap) | Wind (~$14.7B, 56%), Solar (~$8.4B, 32%), Geothermal and other (~$3.1B, 12%) | $26.2B total (Treasury) | Treasury disbursed $26.2B to 109,766 clean energy projects (2009-2018). This amount is partially reflected in the solar and wind grant streams in the charts, but may be understated. Wind received 56% of dollars despite only 1% of project count. The technology-level annual disbursement breakdown is not fully reconciled against chart grant data; a gap of $5-15B may exist. |
| 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., Battery mfg. (Ultium, BlueOval SK), Clean vehicles, Grid | $40B+ committed post-IRA | Only nuclear (Vogtle, Palisades) is tracked in this report. The broader LPO portfolio for battery/solar manufacturing is $40B+ in face value and growing. Excluded because credit subsidy costs are not publicly disaggregated by technology. |
| Section 45X Mfg. PTC | Solar components, Wind components, Battery cells, Inverters | $30-60B over 2023-2032 (JCT) | Manufacturing credit, not deployment. Excluded to maintain deployment-focused framing, but magnitude rivals several included categories. OBBBA FEOC restrictions may reduce utilization. |
| 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. |
| 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 dramatically — solar module costs declined 99%+ since 1977 in real terms. Expressing early solar R&D in 2024 dollars gives it apparent parity with modern dollar amounts, but the purchasing power for actual hardware was very different. (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.