S. 2444 — End Polluter Welfare Act of 2025

This section repeals statutory royalty relief incentives under the Energy Policy Act of 2005 for natural gas production from ultra-deep wells (i.e., perforated interval top at least 20,000 feet true vertical depth below mean sea level, with suspension volumes of at least 35 billion cubic feet) and deep wells in shallow Gulf of Mexico waters less than 400 meters deep west of 87 degrees, 30 minutes west longitude (§§344 and 345, 42 U.S.C. §§15904, 15905). (As background, these provisions directed the Secretary of the Interior to issue regulations providing royalty suspensions on qualifying Outer Continental Shelf leases to encourage production from challenging reservoirs.) The section also strikes subparagraph (B) of section 8(a)(3) of the Outer Continental Shelf Lands Act (43 U.S.C. 1337(a)(3)), makes conforming changes to the Energy Policy Act table of contents, and prohibits royalty relief under any lease issued under section 8 of such Act. (Thus, no new royalty suspensions may be granted on Outer Continental Shelf leases.)

This section increases minimum royalty rates under the Mineral Leasing Act for federal coal, oil, and natural gas leases as follows: (1) for coal leases issued under §7(a) (30 U.S.C. 207(a)), to 18¾ percent (from 12½ percent); (2) for leases on lands where oil or natural gas is discovered under §14 (30 U.S.C. 223), to 18¾ percent (from 12½ percent); and (3) for competitive oil and gas leases under §17 (30 U.S.C. 226), to 18¾ percent (from 16 2/3 percent) or not less than 18¾ percent (from 16 2/3 percent) in specified provisions.

This section revises the royalty rates for oil and gas leases on the outer Continental Shelf (OCS) under cash bonus bidding systems in three instances—subparagraphs (A), (C), and (F)—to 18 3/4 percent (from not less than 16 2/3 percent but not more than 18 3/4 percent during the 10-year period beginning August 16, 2022, and not less than 16 2/3 percent thereafter). (Thus, the Secretary must now fix the royalty at 18 3/4 percent in amount or value of production saved, removed, or sold, with no time-limited range or lower minimum.)

This section prohibits payment of interest on any overpayment of oil and gas royalties under the Federal Oil and Gas Royalty Management Act of 1982. (Thus, lessees that overpay royalties receive refunds without interest.)

This section removes statutory liability limits under the Oil Pollution Act of 1990 (OPA) for oil spill responsible parties as follows: (1) for offshore facilities except deepwater ports, eliminates the additional $75 million cap beyond removal costs (previously, liability capped at all removal costs plus $75 million), basing liability instead on removal costs and amounts under OPA section 1002 (i.e., effectively unlimited strict liability); (2) excludes onshore pipelines transporting diluted bitumen, bituminous mixtures, or oil manufactured from bitumen from the $350 million cap applicable to other onshore facilities and deepwater ports; and (3) subjects such pipelines to liability under OPA section 1002 (i.e., effectively unlimited strict liability). (As background, OPA establishes strict liability for removal costs and damages up to limits in section 1004(a), beyond which claims may be paid from the Oil Spill Liability Trust Fund or pursued on a fault basis.)

This section defines "international financial institution" to include each institution listed in section 1701(c) of the International Financial Institutions Act and the North American Development Bank. It rescinds from the unobligated balance of U.S. contributions to such institutions an amount equivalent to any support the institution provides for a project involving the production or use of fossil fuels. It prohibits any future U.S. contributions to such institutions unless the institution agrees not to use the funds to support any such project.

This section terminates the authority of the Secretary of Energy to carry out the Office of Fossil Energy and Carbon Management (OFECM) at the Department of Energy. (As background, OFECM conducts research, development, and demonstration activities for fossil energy technologies, including carbon capture, utilization, and storage.) It further rescinds all unobligated funds made available to OFECM as of enactment and prohibits expenditure of any funds made available to OFECM after enactment, except as necessary to terminate ongoing research as determined by the Secretary in consultation with other federal agencies.

This section prohibits the Loan Programs Office (LPO) of the Department of Energy from using funds for any project supporting fossil fuels, carbon capture, or hydrogen, except for projects supporting qualified clean hydrogen (as defined in section 45V(c) of the Internal Revenue Code of 1986). (LPO provides loan guarantees and direct loans for innovative energy projects, including under Title XVII of the Energy Policy Act of 2005.)

This section removes carbon capture and storage systems from the list of ineligible projects under the biorefinery assistance program. (As background, the program provides loan guarantees to eligible entities for developing, constructing, and retrofitting commercial-scale biorefineries using eligible technologies to produce advanced biofuels, renewable chemicals, or biobased products. Thus, such systems are now eligible.)

This section eliminates eligibility for Department of Energy loan guarantees under the innovative technology loan guarantee program for (1) advanced fossil energy technology, including coal gasification; and (2) refineries (i.e., facilities refining crude oil into gasoline). The section also strikes the separate authority for gasification project guarantees and makes conforming amendments to related provisions. (As background, the program provides federal loan guarantees to reduce lender risk for deploying new or significantly improved clean energy technologies that avoid, reduce, utilize, or sequester greenhouse gas emissions or air pollutants.)

This section prohibits the Secretary of Agriculture from making a loan under title III of the Rural Electrification Act of 1936 (7 U.S.C. 931 et seq.)—which authorizes Rural Utility Service loans and guarantees for rural electrification and telecommunications infrastructure—for any project that uses fossil fuel.

This section prohibits the United States International Development Finance Corporation, the Export-Import Bank of the United States, the United States Trade and Development Agency, the United States Agency for International Development, and the Millennium Challenge Corporation from obligating or expending any appropriated or otherwise available funds—on or after the date of enactment—to support any project, transaction, or other activity involving the production or use of fossil fuels.

This section prohibits the Department of Transportation (including the Federal Railroad Administration) from using any appropriated funds for grants, loans, loan guarantees, or other direct assistance to rail facilities or port projects that transport fossil fuel, notwithstanding any other provision of law.

This section eliminates the exemptions from owner or operator liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) for certain large lenders. Specifically, the exemptions do not apply to lenders that are (1) an investment company registered under the Investment Company Act of 1940, an investment adviser (as defined in the Investment Advisers Act of 1940), or a broker or dealer (as defined in the Securities Exchange Act of 1934) with $250 billion or more in assets under management; or (2) a bank holding company (as defined in the Bank Holding Company Act of 1956) with $10 billion or more in total consolidated assets.

This section terminates multiple tax incentives, credits, deductions, and special rules related to fossil fuel production, extraction, and compliance (by adding new IRC §7875), generally effective after the date of enactment of the End Polluter Welfare Act of 2025 as follows: (1) for taxable years beginning after enactment, IRC §§43 (enhanced oil recovery credit), 45I (credit for oil and natural gas from marginal wells), 461(i)(2) (special rule for spudding oil or natural gas wells), 469(c)(3)(A) (working interests in oil and natural gas property), and 613A (percentage depletion limits for oil and natural gas wells); (2) for property placed in service after enactment, IRC §168(e)(3)(C)(iii) (certain property classification) and §169 (amortization of atmospheric pollution control facilities); (3) for costs or expenses paid or incurred after enactment, IRC §§179B (capital costs for EPA sulfur regulations) and 468 (mining and solid waste reclamation costs); (4) no new credits certified under IRC §48A (qualifying advanced coal project credit) after enactment; and (5) for obligations issued after enactment, IRC §148(b)(4) (safe harbor for prepaid natural gas). (Thus, fossil fuel producers and related taxpayers lose these benefits prospectively.) It makes conforming amendments to IRC §613(d) and the table of sections for subchapter C of chapter 80.

This section excludes fossil fuel activities—defined as the exploration, development, mining or production, processing, refining, transportation (including pipelines), distribution, or marketing of coal, petroleum, natural gas, or fuel derivatives thereof—from multiple tax benefits after the date of enactment by (1) denying the special depreciation allowance under IRC §168(k) for property primarily used in such activities; (2) excluding gains or losses from such activities from qualified business income under IRC §199A; (3) disqualifying research related to such activities from the credit for increasing research activities under IRC §41; (4) excluding income from such activities from foreign-derived intangible income under IRC §250; and (5) prohibiting like-kind exchanges of real property used in such activities under IRC §1031 (with an exception for certain motor vehicle service stations and convenience stores).

This section revises the amortization rules for geological and geophysical expenditures (i.e., costs incurred for exploration activities such as seismic surveys in oil, gas, and geothermal development) by (1) extending the amortization period to 84 months (from 24 months), (2) establishing a mid-month convention under which amounts paid or incurred during a month are treated as paid on the month's midpoint, and (3) striking paragraph (5). The amendments apply to amounts paid or incurred after the date of enactment.

This section classifies natural gas gathering lines—the original use of which commences with the taxpayer after the date of enactment—as 15-year property under the general depreciation system (from 7-year property placed in service after April 11, 2005) and as 22-year property under the alternative depreciation system. (Natural gas gathering lines transport unprocessed natural gas from production wells to processing plants or centralized delivery points.) The amendments apply to property placed in service on or after the date of enactment, except for property subject to a binding construction contract or, if self-constructed, started construction before the date of this Act's introduction.

This section terminates the last-in, first-out (LIFO) inventory accounting method under IRC §472(a) and IRC §473 for taxpayers engaged in the production, refining, processing, transportation, or distribution of oil, natural gas, or coal for taxable years beginning after enactment of the End Polluter Welfare Act of 2025. (LIFO allows taxpayers to value inventories by assuming the most recently purchased goods are sold first, typically reducing taxable income during periods of rising prices.) It treats any required change to a different inventory method as initiated by the taxpayer with the consent of the Secretary of the Treasury.

This section repeals the percentage depletion allowance under IRC §613 for coal, lignite, and oil shale (other than oil shale described in subsection (b)(5)) for taxable years beginning after enactment. (Percentage depletion permits extractors to deduct a specified percentage of gross income from the property—10% for coal and lignite under former §613(b)(4), and 15% for oil shale under former §613(b)(2)—generally exceeding the cost depletion alternative.) Conforming amendments strike these resources from §613(b)(2) and (b)(4).

This section terminates capital gains treatment for royalties from coal (including lignite) under IRC §631(c), limiting such treatment to iron ore only, for dispositions after the date of enactment. (As background, §631(c) allows a lessor of domestic iron ore or coal reserves to elect capital gains treatment—rather than ordinary income—for royalties received based on lessee production; conforming amendments update statutory headings and §1231(b)(2), which defines §1231 assets.)

This section establishes special rules under new IRC §901(n) disallowing foreign tax credits for amounts paid or accrued by dual capacity taxpayers—as defined, persons subject to a foreign levy who receive (directly or indirectly) a specific economic benefit from the foreign country or U.S. possession—to such country for activities involving the production, refining, processing, transportation, or distribution of fossil fuels (i.e., coal, petroleum, natural gas, or derivatives used as fuel), if the country lacks a generally applicable income tax or if the amount exceeds what would be paid under such a tax (i.e., one substantially applied by its terms and practice to non-dual capacity taxpayers, citizens/residents, and entities organized under its laws). (As background, the foreign tax credit under §901 mitigates double taxation by allowing U.S. taxpayers a dollar-for-dollar credit against U.S. tax for foreign income taxes paid; dual capacity rules distinguish creditable taxes from payments for government-provided economic benefits, such as resource extraction rights.) The provision applies to taxes paid or accrued in taxable years beginning after enactment, notwithstanding U.S. tax treaties.

This section increases the Oil Spill Liability Trust Fund (OSLTF) financing rate—imposed as an excise tax on crude oil received at U.S. refineries and petroleum products entered into the United States to maintain the fund's balance for oil spill response, cleanup, and claims—to 10 cents per barrel (from 9 cents) for crude oil received or petroleum products entered after December 31, 2025. The section also raises the unobligated balance threshold that triggers application of the rate to $2 billion (from $1 billion).

This section expands the definition of crude oil subject to the Oil Spill Liability Trust Fund excise tax (i.e., imposed by IRC §4611) to include crude oil condensates, natural gasoline, and synthetic crude oil (i.e., bitumen and bituminous mixtures; oil derived from bitumen and bituminous mixtures including tar sands; liquid fuel derived from coal; and oil derived from kerogen-bearing sources including oil shale). The section (1) authorizes the Secretary of the Treasury to classify additional fuel feedstocks or finished fuel products customarily transported by pipeline, vessel, railcar, or tanker truck as taxable crude oil or petroleum products if consistent with the definition of oil under the Oil Pollution Act of 1990 and produced in sufficient commercial quantities to pose a significant spill risk; and (2) makes a conforming amendment to the definition of United States by striking language limiting it to oil from a well located in the United States. The amendments apply to oil and petroleum products received or entered during calendar quarters beginning more than 60 days after enactment.

This section denies tax deductions under IRC §162 for any removal costs or damages for which a taxpayer is liable under §1002 of the Oil Pollution Act of 1990 (33 U.S.C. 2702)—covering responsible parties (i.e., vessel or facility owners or operators) for oil discharged or threatening discharge into navigable waters, adjoining shorelines, or the exclusive economic zone. The denial applies to liabilities arising in taxable years ending after enactment.

This section establishes a new excise tax of 13% on the removal price of crude oil or natural gas produced from federal submerged lands on the outer Continental Shelf (OCS) in the Gulf of Mexico under U.S. leases (i.e., taxable crude oil or natural gas), effective for fuel removed after December 31, 2025. The tax, paid by the producer (i.e., holder of the economic interest), allows a credit for federal royalties paid on such production (not to exceed the tax liability); the removal price is generally the sales price (or constructive sales price under IRC §613 for related-party sales, unsold fuel, or on-premises refining), subject to IRS adjustment to fair market value. The section further requires quarterly tax withholding and deposits, annual taxable periods and returns, and recordkeeping; makes the net tax (after royalty credit) deductible under IRC §164(a); and directs the IRS to issue related regulations.

This section amends the definition of qualifying income for publicly traded partnerships (PTPs) in IRC §7704(d)(1) by adding coal, petroleum, natural gas, or any derivative thereof used for fuel to the activities enumerated after the reference to §613(b)(7). (Thus, income and gains from such fossil fuel activities no longer qualify, causing PTPs with more than 10% gross income from those sources to be taxed as corporations.) The amendment applies to taxable years beginning after the date of enactment.

This section revises the amortization of qualified tertiary injectant expenses (i.e., costs of substances injected in qualified enhanced oil recovery projects to extract additional oil) to a ratable deduction over 84 months (from 36 months) beginning on the date paid or incurred, applies a mid-month convention (treating monthly expenses as incurred at month midpoint), and specifies that no other depreciation or amortization deduction is allowed for such expenses. The changes apply to expenses paid or incurred in taxable years beginning after enactment.

This section revises the tax treatment of development expenditures for mines or other natural deposits (excluding oil or gas wells) under IRC §616 by requiring such expenditures—paid or incurred after disclosure of ores or minerals in commercially marketable quantities—to be deducted ratably over 84 months (from prior elective deduction over 24 months) beginning on the date paid or incurred. (It applies a mid-month convention; establishes this as the exclusive recovery method with no other depreciation, amortization, or abandonment deduction allowed; and makes conforming amendments to 10 other IRC sections striking prior references to §616(a) or related provisions.) The changes apply to expenditures paid or incurred in taxable years beginning after enactment.

This section revises the tax treatment of mining exploration expenditures—costs paid or incurred to ascertain the existence, location, extent, or quality of any ore or mineral deposit before the development stage of the mine—by requiring their deduction ratably over an 84-month period (from prior elective amortization over 120 months) beginning on the date paid or incurred, using a mid-month convention. The section specifies that such expenditures receive no other depreciation or amortization and that amortization continues (with no abandonment deduction allowed) if the related property is retired or abandoned during the 84-month period. It also makes conforming amendments to multiple IRC sections, including (1) repealing the alternative minimum tax adjustment under §56(a)(2) and environmental tax under §59(e); (2) eliminating the 30% deduction reduction for integrated oil companies under §291(b) (now limited to intangible drilling costs); (3) removing such expenditures from charitable contribution reductions under §170(e), uniform capitalization rules under §263A(c)(3), partnership treatment under §703(b)(2), and gain recognition under §1254(a); and (4) capitalizing only intangible drilling costs (not mining exploration costs) ratably over 60 months under §312(n)(2). The amendments apply to expenditures paid or incurred in taxable years beginning after enactment.

This section revises the treatment of intangible drilling and development costs (IDCs) paid or incurred in taxable years beginning after enactment by requiring oil and gas well IDCs—previously eligible for elective immediate expensing—to be amortized ratably over 84 months from the mid-point of the month paid or incurred, with no separate depreciation or abandonment deductions allowed. Geothermal well IDCs remain eligible for elective immediate expensing. The section makes conforming amendments to various Internal Revenue Code provisions, including (1) limiting the alternative minimum tax adjustment in §57(a)(2) to geothermal properties; (2) updating §59(e) references to apply only to geothermal IDCs; (3) revising §263A(c)(3) to cover only geothermal wells; (4) striking §291(b), which reduced corporate IDC deduction benefits by 20%; and (5) updating §312(n) references to apply only to geothermal IDCs.

This section increases the per-ton excise tax rates on coal sold to fund the Black Lung Disability Trust Fund (i.e., provides benefits to coal miners totally disabled by black lung disease and payments to survivors), (1) to $1.38 (from $1.10) for underground mined coal, and (2) to $0.69 (from $0.55) for surface mined coal. The increased rates apply on and after the first day of the first calendar month beginning after enactment.

This section eliminates eligibility for the renewable electricity production tax credit for refined coal by striking the definition of refined coal, related special rules, and higher credit rate provisions from Section 45 of the Internal Revenue Code and making conforming amendments to Sections 38 and 45K. The amendments apply to coal produced after December 31, 2025.

This section establishes foreign base company oil related income as a new category of subpart F income under Section 954(a)(4) of the Internal Revenue Code, applicable to controlled foreign corporations (CFCs) that are large oil producers (i.e., related group average daily production of foreign crude oil and natural gas equals or exceeds 1,000 barrels for the taxable year or prior year, determined under rules similar to former Section 613A). (As background, subpart F income of a CFC is includible in the current-year U.S. gross income of its U.S. shareholders with 10% or greater ownership to limit tax deferral.) Foreign base company oil related income generally includes foreign oil related income (as defined in Section 907(c)(2) and (3)) other than income derived in a foreign country from oil or gas extracted there or sold/used/loaded there as fuel, excluding foreign personal holding company income; the amendments apply to taxable years of foreign corporations beginning after enactment and related U.S. shareholder taxable years. Conforming amendments to Sections 952 and 954 (1) include this income in the high-tax exception, (2) limit its reduction under the de minimis rule and full-inclusion exceptions, and (3) provide it is not treated as other base company income.

This section repeals the exclusion of foreign oil and gas extraction income from the definition of tested income under the global intangible low-taxed income (GILTI) rules. (As background, GILTI generally requires U.S. shareholders of controlled foreign corporations to include in income the excess of net tested income over 10% of the adjusted basis of depreciable tangible property used in producing tested income.) The repeal applies to taxable years of foreign corporations beginning after the date of enactment and to taxable years of U.S. shareholders in which or with which such taxable years end.

This section terminates the carbon oxide sequestration tax credit under Section 45Q for qualified carbon oxide captured after the date of enactment. (Thus, the credit—available at up to $85 per metric ton for direct air capture storage, $60 for other geologic storage, $35 for enhanced oil recovery, and $36 for utilization, among other rates—is allowable only for captures on or before enactment.) (As background, Section 45Q incentivizes capture, secure geological storage, enhanced oil recovery use, or utilization of carbon oxide to mitigate greenhouse gas emissions from industrial and energy sources.) This section further requires the Secretary of the Treasury to submit a public report to Congress within six months of enactment identifying (1) each taxpayer that claimed the credit since its original enactment, (2) the total credit amount allowed to each, and (3) a breakdown of those amounts by sequestration method—secure geological storage (not for enhanced recovery or utilization), use as a tertiary injectant in qualified enhanced oil or natural gas recovery with secure storage, or other utilization under Section 45Q(f)(5). It authorizes disclosure of taxpayer return information solely for the report, notwithstanding confidentiality rules under Section 6103.

This section eliminates eligibility for drawback refunds of taxes imposed under section 4611 of the Internal Revenue Code of 1986 (i.e., taxes on crude oil received at U.S. refineries and on imported petroleum products, to fund the Oil Spill Liability Trust Fund) under the substitution drawback provision (19 U.S.C. 1313(j)). (As background, substitution drawback allows refunds of duties, taxes, and fees paid on imported merchandise when domestically produced merchandise classifiable under the same 8-digit HTSUS subheading is substituted in manufacturing articles that are exported or destroyed under Customs supervision within five years of importation.) The prohibition applies to articles entered, or withdrawn from warehouse for consumption, on or after January 1, 2026.

This section modifies the clean hydrogen production tax credit (IRC §45V)—which provides a tax credit based on lifecycle greenhouse gas emissions rates for hydrogen produced at qualified facilities—for facilities placed in service after December 31, 2025, by (1) reducing the credit amount to $0.60 per kilogram of qualified clean hydrogen (from $3.00), subject to annual inflation adjustment; (2) redefining qualified clean hydrogen as hydrogen produced through an electrolyzer powered by electricity generated from qualified renewable energy resources (wind, solar, geothermal, marine and hydrokinetic renewable energy, or hydropower) at a facility in the same region (per DOE's National Transmission Needs Study, October 30, 2023) that was placed in service no more than 36 months earlier and generated such electricity at least one hour prior to the electrolyzer's use; (3) eliminating the requirement for Treasury regulations or guidance on determining lifecycle greenhouse gas emissions; and (4) making conforming amendments, including to cross-references in §§45, 48, and 6417 and extending certain termination dates to December 31, 2025 (e.g., elective payment eligibility under §6417 and certain ITC eligibility under §48). It also sets the energy investment tax credit percentage for qualified clean hydrogen production facilities to 6 percent.

This section revises the definition of "lead agency" in section 9909(c)(1) of the William M. (Mac) Thornberry National Defense Authorization Act for Fiscal Year 2021 (15 U.S.C. 4659(c)(1)) to mean, with respect to a covered activity, the Federal agency that proposed the covered activity (from the meaning given the term in section 111 of NEPA (42 U.S.C. 4336e)).

This section repeals sec. 50264 of the Inflation Reduction Act of 2022, which required oil and gas lease sales under the 2017-2022 Outer Continental Shelf leasing program. This section also repeals sec. 50265 of such Act (43 U.S.C. 3006), which during the 10-year period beginning August 16, 2022, prohibited the Secretary from issuing rights-of-way for wind or solar energy development on federal lands unless an onshore oil and gas lease sale had been held in the prior 120 days and at least 2,000,000 acres (or 50% of acreage with expressions of interest, whichever is less) had been offered in the prior year, and from issuing offshore wind leases unless an offshore oil and gas lease sale had been held and at least 60,000,000 acres offered in the prior year.

This section (1) eliminates eligibility of metallurgical coal for the advanced manufacturing production tax credit under IRC §45X by striking its 2.5% credit rate and related exceptions from phaseout provisions; (2) reinstates prior-law treatment of intangible drilling and development costs for oil and gas by repealing amendments made by section 70523 of Public Law 119-21; (3) modifies qualifying income for publicly traded partnerships under IRC §7704 to limit the hydrogen exclusion to qualified clean hydrogen (as defined in §45V) and strikes a related clause; (4) repeals oil and gas, mining, and energy provisions of Public Law 119-21, including the methane mitigation and monitoring program ($850 million appropriated for FY2022, available through September 30, 2028) and methane mitigation from marginal conventional wells ($700 million appropriated for FY2022, available through September 30, 2028)—which provided grants, rebates, loans, and technical assistance to reduce methane emissions from petroleum and natural gas systems, monitor emissions, plug wells, and support affected communities; (5) accelerates under Clean Air Act §136(g) the methane waste emissions charge to calendar year 2024 (from calendar year 2034); and (6) repeals project sponsor opt-in fees for National Environmental Policy Act environmental reviews.

This section repeals Public Law 119–2 (139 Stat. 7) and directs the Administrator of the Environmental Protection Agency to implement the final rule entitled “Waste Emissions Charge for Petroleum and Natural Gas Systems: Procedures for Facilitating Compliance, Including Netting and Exemptions” (89 Fed. Reg. 91094, November 18, 2024) as if Public Law 119–2 had not been enacted into law.

This section defines "subsidy for fossil-fuel production" to include direct funding, tax treatments or incentives, risk-reduction benefits, financing assistance or guarantees, royalty relief, or other financial benefits to fossil-fuel companies for producing fossil fuels. It directs the Secretary of the Treasury, in coordination with the Secretary of Energy (and the Commissioner of Internal Revenue for the second report), to submit two reports to Congress within one year of enactment: (1) identifying each federal law or regulation (excluding those amended by this Act) providing such a subsidy; and (2) analyzing applicable recovery periods under the accelerated cost recovery system (IRC §168, i.e., MACRS depreciation) for fossil-fuel production property—including pipelines, power generation property, refineries, and drilling equipment—to determine if any constitute such a subsidy. For any such property determined to receive a subsidy, the section eliminates application of IRC §168 for property placed in service in taxable years beginning after the determination date, provided the determination is published before the first day of the taxable year.