Methodological Appendix

GHG baselines for 2005 and 2030

Economy-wide GHG baselines for 2005 and 2030 start with the country’s 7^th National Communication associated with its 3rd and 4th Biennial Report (“A Review of Sustained Climate Action through 2020”).^[1] The 2030 baseline has been updated to account for final regulatory actions since the publication of the 7^th National Communication.^[2] These include: (1) the prospective impact of EPA Light-Duty Vehicle Greenhouse Gas Standards^[3] / NHTSA Corporate Average Fuel Economy Standards^[4] for light-duty vehicles, as estimated by the Department of Energy; and (2) the phasedown of HFCs under the American Innovation and Manufacturing (AIM) Act.^[5] The resulting 2030 economywide GHG baseline is 23% below 2005 emissions. Finally, the impacts of the Bipartisan Infrastructure Law and Inflation Reduction Act on 2030 GHG emissions are estimated by subtracting power, industry, buildings, transportation, and other emissions savings estimates – as described below.

Power

DOE’s assessment of potential power-sector GHG impacts relies on an analysis conducted using an advanced power-system planning model developed by the National Renewable Energy Laboratory: Regional Energy Deployment System (ReEDS) model. The ReEDS model simulates the evolution of the U.S. bulk power system—generation, transmission, and storage—from present day through 2050 given projections of future load, fuel prices, and the cost and performance of power system technologies, as well as representations of existing policies and regulations.^[6] Among many features, the model represents the power system with a high-level of both spatial and temporal resolution in order to capture variability in electricity load and resource availability, and to ensure that investment portfolios continue to meet reliability standards.

In this analysis, simulations were conducted to identify least-cost power-sector investment portfolios under two scenarios: (1) a ‘No New Policy' scenario that simulates power sector evolution without the Bipartisan Infrastructure Law (BIL) and Inflation Reduction Act (IRA) and with load growth consistent with EIA’s Annual Energy Outlook 2021 Reference case^[7], and (2) a ‘BIL-IRA’ scenario that includes key provisions from the two laws and assumes increased load growth due to increased electrification in the transportation, buildings, and industrial sectors induced by other BIL and IRA provisions. Both scenarios were evaluated under mid-case technology cost and performance assumptions from NREL’s Annual Technology Baseline 2021^[8] and with natural gas and other fuel prices from EIA’s Annual Energy Outlook 2022 Reference case. Results represent projections of what is most economic to build and operate within the bulk power system under alternative future market, technology, and policy conditions, and do not consider the full suite of non-economic considerations. The GHG impacts of IRA and BIL were assessed as the difference between the No New Policy and the BIL-IRA scenarios.

The BIL-IRA scenario captures the major tax incentives proposed in the Inflation Reduction Act, including production-based and investment-based tax credits for new clean electricity generation, energy storage, hydrogen production, and carbon capture and sequestration (CCS), as well as tax credits for existing nuclear plants. Developers of new clean electricity sources are assumed to meet labor standards in the legislation and are therefore eligible to elect either the PTC or the ITC at their full values: 10-years at $25/MWh and 30%, respectively. Clean electricity technologies are also generally assumed to access, on average, one of the two tax credit bonus provisions for domestic content and energy communities, yielding a 10% (PTC) or 10 percentage point (ITC) increase in tax credit values. Distributed solar and storage technologies receive a 30% ITC and the impact of the ITC was estimated using NREL’s Distributed Generation Market Demand (dGen) model. The allocated enhanced tax credit for low-income solar is assumed to meet the 1.8 GW/year cap, in part with the help of the new EPA Greenhouse Gas Reduction Fund (60103). CCS technologies are assumed to store CO₂ in geologic sites, and therefore are eligible for the 12-year, $85/ton CO₂ tax credit. For the purposes of the power sector modeling, only hydrogen used in the power sector is considered; in the power sector, the hydrogen PTC is represented in two forms, steam methane reforming and electrolysis (note that the broader emissions impacts of the hydrogen PTC are included in the analysis of other sectors presented in this brief). The PTC for existing nuclear power plants is assumed to ensure continued operation of most of the existing nuclear fleet through 2032. Across most eligible technologies, tax credit values are reduced under the assumption that monetizing the credits results in some loss of their value. Five-year accelerated depreciation is assumed.

Separate from ReEDS, DOE also assessed the potential impacts of a wide variety of additional loan, grant, and other programs on the power sector. In these cases, DOE generally assumes that roughly half of the prospective impacts of these programs are captured in ReEDS results: in effect, these programs are assumed to help direct and facilitate the modeled outcomes. The other half of the impacts are assumed to be additional to otherwise modeled outcomes; DOE therefore applies simplifying assumptions to broadly estimate the impacts of these provisions. Provisions modeled in this way include various transmission authorities (e.g., BIL: 40106, 40101, 40103; IRA: 50151); several incentive, grant, and demonstration programs (BIL: 40541, 40331, 40332, 40333, 40342, 41002, 41004; IRA: 60114); several programs to support rural utilities and areas under IRA (22001, 22002); and two additional programs intended to support energy and rural communities established under IRA (50144, 22004). To be clear, this is not an exhaustive list of every power sector provision in BIL and IRA. Those provisions that are not explicitly modeled or assessed are instead assumed to help resolve institutional frictions in power-system investments and, therefore, facilitate the projected outcomes otherwise reported here.

Industry

DOE’s analysis of the industrial provisions in IRA includes an assessment of both tax incentives and other forms of financial assistance. For CCS policies, including the 45Q tax credits, carbon capture demonstrations, and carbon transport and storage infrastructure investments, DOE uses a version of the National Energy Modeling System (NEMS) with enhanced representation of industrial CCUS, coal CCUS retrofits with biomass cofiring, and direct air capture (DAC). For clean hydrogen, DOE assumes that production reaches 5 million metric tons of clean hydrogen by 2030, driven by the production tax credit and supported by the hydrogen hub funding in BIL, with assumptions around the amount supplied by each carbon intensity tier.

For the Advanced Industrial Facilities Deployment Program, DOE assumes a mix of project types across industrial subsectors and facility sizes, and applies emissions reductions and cost estimates provided by industry experts and from similar projects. For federal procurement programs (IRA: 60503, 60504, 60506), DOE employs the lower end of a range of impact sourced from an external analysis using data on carbon intensity, federal procurement data, and industry cost estimates.^[9]

These estimates do not fully consider potential interactive effects of the deployment programs. For instance, the estimated impact could be higher if 45Q and the hydrogen production tax credit collectively make retrofits of additional facilities cost-effective. Additionally, these early industrial investments could decrease the cost for the subsequent adoption of emissions-saving advanced industrial technologies, further amplifying the impact of this program.

Buildings

DOE assessed the impacts of several provisions in both BIL and IRA that will result in emissions reduction from the U.S. commercial and residential buildings sectors. This included efficiency tax incentives (IRA: 13301, 13303, 13304) and direct rebate programs (IRA: 50121, 50122). It also included funding to state and local governments for building codes (IRA: 50131; BIL: 40511) and other programs that will result in reduced emissions from buildings (Including IRA: 22002, 30001, 30002, 30202, 50123, 60103, 60114, 60201, 60502, 80003; and BIL: 40502, 40541, 40551, 40552, 40554, 40109).

DOE drew from existing public analyses, both retrospective and prospective, on the impacts of programs and investments in reducing energy demand and emissions from the U.S. buildings sector. Sources included previous impact evaluations for the Weatherization Assistance Program,^[10] State Energy Program,^[11] Energy Efficiency and Conservation Block Grant (EECBG) program^[12]; modeling of residential equipment incentives using a version of NEMS^[13]; a review of other public estimates of the impact of buildings efficiency tax credits^[14][15], and EIA projections.

Estimates of buildings sector emissions reductions depend heavily on the assumed emissions intensity of electricity consumed by buildings. For this analysis, DOE’s assessment of emission reductions in the buildings sector accounts for changes in grid emissions intensity that are projected in the power sector analysis of BIL and IRA provisions, reducing the per-KWh emissions impact of reducing electricity demand in buildings, and increasing the emissions savings estimated from electrifying building energy demand. Additional opportunities to reduce emissions through grid-interactive efficient building technologies were not directly assessed, and have the potential to achieve greater emissions reductions from the building sector in 2030 and beyond.^[16]

Transportation

DOE assessed the GHG savings associated with transportation ranging from light, medium- and heavy duty on-road vehicles, off-road vehicles and port applications, and aviation. DOE analyzed direct measures that encourage a switch to clean vehicles, end-use equipment, and fuels (IRA: 13201, 13202, 13203, 13204, 13401, 13402, 13403, 60101, 60102, 60104, 70002), while considering the complementary enabling roles of charging, refineries, and other fueling infrastructure (IRA: 13404, 40007), as well as supply chain and manufacturing investments (IRA: 13502, 30001, 50142, 50143). Various tax credits, programs, grants, and incentives that target a given sub-sector were modeled and adjusted to reduce double-counting. This analysis does not fully quantify the avoided upstream emissions from fueling transportation applications with a cleaner power system. Additionally, cost and emissions benefits from manufacturer learning and market transformation are unquantified. Consequently, the estimates presented here should be considered a lower-end assessment of savings.

To quantify emissions savings, DOE leveraged tools to model transportation^[17] and energy^[18] consumption, benchmark technology cost and performance,^[19] analyze measure-based^[20] and fuel lifecycle^[21] impacts, dynamically simulate supply chains,^[22] and plan fleet procurements. References to recent decarbonization scenario assessments,^[23] market outlooks,^[24] evaluations of state^[25] and national^[26] deployment programs, driver profiles,^[27] existing regulations and other data assisted the analyses.

Of note, DOE analyzed the Clean Vehicle Credit and its interactions with infrastructure and supply chain measures. Informed by transportation policy simulation tools,^[28] DOE used Office of Policy (OP)-NEMS to calculate emissions reductions. This consumer and emissions impact of the new credit was compared to a reference case where the existing plug-in electric vehicle tax credit phases out when automakers reach their 200,000 sales cap. Schedules requiring minimum values of critical minerals and battery components were considered in scenarios measuring the share of prospective EV purchases that would be ineligible for a tax credit or eligible for either $3,750 or $7,500 from 2023 to 2030. DOE incorporated information on geological resources, international trade flows, trends in battery chemistries, supplier agreements, economic valuation of the critical minerals, qualifying battery components and the balance of pack systems, announcements of automaker battery production and vehicle assemblies, and U.S. government coordination to scale allied production to approximate a compliance schedule for new electric vehicles. The scenarios applied the tax credit levels as reductions to the cost of purchasing an EV, weighted according to the level of market compliance with the critical mineral and battery component value thresholds. OP-NEMS used the Transportation Sector Module to calculate the sales of EVs, fuel and electricity consumption, and associated GHG savings. Data on the relationship between automotive manufacturers’ suggested retail prices and prospective EV purchasers’ annual gross income were also evaluated. Finally, the analysis considered how to attribute GHG savings to the Clean Vehicle Credit and to sectoral programs for light duty electric vehicles, given the number of supply- and demand-side measures that would influence automaker product planning and marketing decisions. Factors quantified and considered included the prospective investments in the domestic battery supply chain funded by the Bipartisan Infrastructure Law, the battery manufacturing production tax credit, Defense Production Act investments for critical minerals, the Advanced Technology Vehicle Manufacturing program, and the Domestic Manufacturing Conversion Grants.

Other

The Inflation Reduction Act also contains provisions related to agricultural conservation and forestry (21001, 21002, 23001, 23002, 23003) as well as oil and natural gas (50264, 50265, 60113). DOE has not assessed these provisions, but instead draws on estimates and insight from federal agency partners^[29] and external analysts.^[30] For example, to estimate the impacts of the climate-smart conservation provisions of the legislation, USDA relied on its published estimates of marginal GHG abatement costs for climate-smart farming practices.^[31] USDA used that analysis in its assessment, to inform investment choices and to quantify changes in adoption due to increased program funding under IRA.

Collectively, IRA’s provisions on agricultural conservation, forestry, oil, and natural gas result in significant net GHG pollution reductions. IRA’s investments in agricultural conservation and forest health, for example, are expected to contribute to over 10% of the overall GHG benefits of the legislation. While oil and natural gas leasing provisions may lead to some increase in GHGs in 2030, those possible increases are dwarfed around 35-to-1 by net estimated pollution reduction from IRA and BIL.

[1] See: https://www.whitehouse.gov/wp-content/uploads/2021/10/ClimateNationalCommunication.pdf

[2] Projections of other non-CO₂ emissions (nitrous oxide and methane), agriculture source projections, and land use, land-use change, and forestry (LULUCF) were also updated with recent estimates.

[3] See: https://www.epa.gov/regulations-emissions-vehicles-and-engines/final-rule-revise-existing-national-ghg-emissions

[4] See: https://www.nhtsa.gov/laws-regulations/corporate-average-fuel-economy

[5] See: https://www.epa.gov/system/files/documents/2021-09/ria-w-works-cited-for-docket.pdf

[6] For more on ReEDS, see: https://www.nrel.gov/analysis/reeds/

[7] See: https://www.eia.gov/outlooks/archive/aeo21/

[8] See: https://atb.nrel.gov/electricity/2021/data

[9] See: https://www.thirdway.org/blog/building-back-better-with-clean-materials-offers-big-ghg-savings

[10] See: https://weatherization.ornl.gov/wap-retrospective/

[11] See: https://www.energy.gov/eere/wipo/downloads/state-energy-program-national-evaluation

[12] See: https://weatherization.ornl.gov/eecbg/

[13] See: https://www.ase.org/sites/ase.org/files/tax-credits-summer-study-paper.pdf

[14] Joint Committee on Taxation cost estimate of H.R. 5376: https://www.democrats.senate.gov/imo/media/doc/21-2093.pdf