How Much Would Expanding Federal Oil and Gas Leasing Increase Global Carbon Emissions?

The US government leases a substantial amount of federally owned lands for oil and gas development, accounting for approximately 12 percent of national oil production and 11 percent of national natural gas production in 2023, not counting production in offshore US waters. Yet approaches to the oil and gas federal leasing can vary widely between administrations. For example, under the Trump administration, oil and gas leasing ranged from 1.1 million acres to 2.2 million acres per year, compared to a range of 75,000 to 249,000 acres under the Biden administration (figures corresponding to fiscal years 2017–2020 and 2021–2023, respectively). Actions to expand or restrict the federal land available for lease in a given year can clearly affect fossil fuel production and global greenhouse gas emissions in the long run, but assessments of such effects have been limited due to inherent complexities and substantial uncertainty. Estimating the effects of expanded oil and gas leasing is important to inform broader policy deliberations around energy policy and permitting reform. In this issue brief, I model the global emissions consequences of a sustained expansion of federal leasing at peak levels from the last decade. The goal of this research is to provide a bounding analysis, estimating the uncertainty range for a high leasing case based solely on authorities within the existing scope of the executive branch. This analysis specifically does not estimate the emissions effects of onshore oil and gas provisions in the recently introduced Energy Permitting Reform Act of 2024 (EPRA). The onshore oil and gas provisions in EPRA are likely to have a more modest effect on emissions than the high leasing scenario analyzed here (see Discussion).

This issue brief builds on past research (e.g., Prest et al. 2024; Prest 2022) to estimate the magnitude of emissions increases from a sustained expansion of oil and gas leasing on federal lands. Evaluating the emissions effects of expanded leasing is particularly challenging, as it involves understanding the anticipated effect of lease sales on oil and gas drilling on federal lands; the resulting increase in federal oil and gas production; the amount of production “leakage,” meaning partial substitution of production between federal lands and other sources of supply; and the greenhouse gas emissions resulting from the net increase in global oil and gas consumption. The central estimate suggests that perpetually expanded oil and gas leasing on federal lands at annual rates consistent with the fastest pace of leasing over the past decade would increase cumulative global greenhouse gas emissions by 1.2 gigatons (billion metric tons) of CO2 equivalent (GtCO2e) over 2024–2050, under a 100-year global warming potential (GWP). For reference, this 1.2 GtCO2e value corresponds to approximately 43 million tons CO2e per year over that 27-year window, or about 0.1 percent of current annual global greenhouse gas emissions. This increase is relative to a business-as-usual (BAU) baseline of about half that amount of leasing. An extensive set of sensitivity analyses suggests that emissions increases are highly unlikely to be outside the 0.6 to 2.1 GtCO2e range. On a territorial emissions accounting basis, US emissions account for approximately 0.2 GtCO2e of the global increase of 1.2 GtCO2e estimated in the central case. This analysis covers onshore development on federal lands and does not consider the potential impacts of expanded offshore development, which accounts for another 14 percent of national US oil production and 2 percent of national gas production.

Figure 1 provides historical context of oil and gas development on federal lands since 2001. The top panel of Figure 1 shows the acres of federal land newly leased annually since 2001 (in orange) alongside the number of wells drilled on federal land each year (in purple). Federal leases typically have a primary term of 10 years by which they must be drilled, meaning that there is a lagged relationship between when leases are issued (the orange line) and when drilling occurs. The delayed nature of this relationship is illustrated by the sustained drilling activity during the 2021–23 period despite reduced lease sales during the Biden administration. Drilling activity on federal land is also driven by economic factors, most notably the prices of crude oil and natural gas. The middle panel (reported in 2022$) shows that higher prices drive more drilling. Overall oil and gas production on federal land, shown in the bottom panel, represents the accumulation of all operating wells, which can operate for decades after they are drilled. This panel shows that oil production (and to a lesser extent, gas production) on federal lands has grown at a rapid pace in recent years even though drilling activity remained much lower over the past decade (2014–23, averaging 1,760 new wells drilled annually) than in the preceding decade (2004–13, averaging 3,470 new wells annually). The shale revolution greatly increased how much oil and gas are produced from each newly drilled well.

Together, the three panels of Figure 1 highlight the key factors driving oil and gas production on federal land:

1. The delayed effect of oil and gas lease sales on drilling activity
2. The important role of oil and gas prices in driving the economics of oil and gas development
3. The accumulation of production from newly drilled wells, including the productivity of those wells

The analytic approach in this issue brief combines a representation of these three factors with estimates of substitution between federal supply and other sources. First, I use time series econometrics to empirically estimate the relationship of drilling on federal land with historical lease sales and oil and gas prices, shown in the top and middle panels of Figure 1. Second, I construct hypothetical alternative future pathways of lease sales and oil and gas prices and run them through the econometric model. The oil and gas price scenarios correspond to the oil price scenarios in the 2023 Annual Energy Outlook (AEO) from the Energy Information Administration (EIA). The oil prices vary widely across these scenarios, averaging $91 per barrel in the reference case during the 2025–50 period, compared with $48 and $175 per barrel in the low and high scenarios, respectively (see Appendix Figure A4).

I construct two hypothetical future pathways of lease sales. The high leasing scenario envisions a leasing pathway between 2025 and 2027 that repeats the amount of acreage leased under the Trump administration from 2017 to 2019, when lease sales peaked at 2.2 million acres, followed by leasing sustained at that high level annually from 2028 through 2050. The business as usual (BAU) scenario envisions lease sales at half the level of the high leasing scenario, with 1.1 million acres leased annually 2028 through 2050. While this approximately 1 million acre BAU scenario remains much higher than the amount of acreage leased during the Biden administration, it is nonetheless similar to the average of 1 million acres leased across the Trump and Biden administrations (2017–23). Thus this baseline can be loosely interpreted as consistent with a scenario of oscillating lease sales between divergent future administrations alternating between phases of high leasing (e.g., 2 million acres per year) and phases of low to zero leasing. While the Inflation Reduction Act (IRA) requires a minimum amount of oil and gas lease sales if the Bureau of Land Management (BLM) wishes to approve wind or solar projects on federal land, the constraint is based on 2 million acres per year or 50 percent of nominated acreage, whichever is smaller. The nominated acreage remains low even in 2023, which was under 0.1 million acres, implying that at least as of that year, the IRA’s constraint was not particularly binding. If the constraint binds more in future years, this suggests the BAU baseline may be too low, implying my estimated emissions impacts may be too large. See Appendix B for more discussion. These leasing scenarios are intentionally stylized and do not correspond precisely to any specific provisions in recently proposed legislation because many of these provisions are difficult to model quantitatively.

Next, I run the paths of lease sales and oil and gas prices through the econometric model to project future federal drilling activity. Future oil and gas production from those newly drilled wells is modeled using average well-level production profiles based on historical averages for production from wells on federal lands (see Appendix Figure A1). The model is calibrated such that cumulative new future oil and gas production from that drilling activity in the BAU scenario matches the federal share of cumulative projected production in the 2023 AEO reference case in barrels of oil equivalent terms (see Appendix A for more details).

New federal production is modeled for each scenario, but to compute the effects on global oil and gas consumption and hence emissions, I must also account for substitution of production between federal lands and other sources of supply, referred to as leakage. The amount of leakage is driven by the elasticities of supply and demand for oil and gas. Prest et al. (2024) conduct a meta-analysis of such elasticities, finding a central estimate for the leakage rate of 57 percent, which I use here (a result also consistent with the range found in Prest 2022). In other words, each incremental barrel of federal oil production is assumed to result in 0.57 barrels of reduced oil production elsewhere and 0.43 barrels of pure increase in oil consumption, and similarly for gas. I use the same emissions factors as in Prest (2022) of 0.43 tons of carbon dioxide (tCO2) per barrel of oil and 0.066 tCO2e per thousand cubic feet (mcf) of gas, which corresponds to a 2.3 percent methane leak rate and a 100-year GWP. Therefore each incremental barrel of federal oil that is produced results in (0.43 barrels) × (0.43 tCO2/barrel) = 0.185 tCO2 of additional global emissions. The calculation for gas is analogous.

The key results are summarized in Table 1, which shows the cumulative 2024–50 incremental global emissions for each of six scenarios due to new federal oil and gas production net of leakage. The six scenarios represent the cross between the two leasing scenarios and three price scenarios. In the reference price scenarios, cumulative global emissions over 2024–50 are about 1.2 GtCO2e higher in the high leasing scenario than in the BAU. The impacts in the high/low oil price scenarios bracket this impact at 0.7 to 2.0 GtCO2e. Importantly, these estimates reflect the change in global emissions, driven by increased oil and gas consumption around the world induced by incrementally lower global oil and gas prices. On a territorial emissions accounting basis, the increased emissions in the United States account for approximately 0.2 GtCO2e of the global increase of 1.2 GtCO2e in the central case. This reflects the EIA’s projected share of global oil and gas demand attributable to the United States, averaging 17 percent between 2024 and 2050 (EIA 2023b). Thus more than 80 percent of the oil and gas consumption, and hence emissions, induced by increased federal production is likely to occur outside the United States. This highlights a key distinction between policies driving fossil fuel demand and those driving its supply: demand-side policies like investments in zero-carbon energy primarily drive emissions reductions in the country implementing them, whereas supply-side policies primarily drive production available for export and consumption abroad.

The econometric results can be summarized by long-run elasticities of federal onshore drilling with respect to acreage leased, estimated at 0.3 (p = 0.03); crude oil prices, estimated at 0.8 (p = 0.002), and natural gas prices, estimated at –0.1 (p = 0.81). These suggest, for example, that a 10 percent increase in acreage leased eventually increases drilling on federal lands by 3 percent. The elasticity with respect to crude oil prices of 0.8 implies that a 10 percent increase in crude oil prices increases drilling by 8 percent, motivating the consideration of alternative price pathways in Table 1. While the leasing elasticity has no obvious analogue in the literature for comparison, the price elasticities are reasonable and in the range of estimates from the literature. The small and statistically insignificant relationship between gas prices and drilling is consistent with the recent oil-directed drilling on federal lands primarily from the New Mexico Permian Basin, seen in the bottom panel of Figure 1.

The resulting pathways of leasing and drilling activity are shown in Figure 2. The relatively low elasticity of drilling with respect to leasing of 0.3 implies that although the high leasing scenario has twice as much new acreage leased as the BAU scenario, it yields much less than twice as much drilling (Figure 2) or emissions (Table 1). Another practical reason is that drilling in the near term will occur primarily on existing leases unaffected by future lease sales. This is clearly consistent with the recent historical experience, as federal drilling remained elevated during the Biden administration despite substantially reduced leasing (Figures 1 and 2).

Beyond the uncertainty in future oil prices addressed in Table 1, there are multiple sources of uncertainty in the assessment of emissions from changes to federal oil and gas leasing, including uncertainty in the accuracy of EIA’s oil and gas production baseline, in the ultimate emissions consequences of incremental natural gas production (i.e., if it substitutes for other fuels with different carbon intensities), and in the leakage rate. Sensitivity analyses addressing these uncertainties are shown in Figure 3. Across the full set of sensitivity analyses, the cumulative global emissions impacts range from 0.6 to 2.1 GtCO2e. I discuss each of these uncertainties in turn.

First, in the BAU base case, the federal production baseline is calibrated to match the cumulative federal production implied by the AEO 2023. However, EIA’s retrospective evaluations (e.g., EIA 2022) demonstrate a consistent pattern of underpredicting the growth of US oil and gas production. Accordingly, EIA has repeatedly revised its production projections upward, particularly from the Permian Basin, which is the source of much of the recent and ongoing growth in onshore oil and gas development on federal lands. While the main analysis in this paper is calibrated to reflect EIA’s most recent projected production trajectories, those trajectories nonetheless imply a substantial slowing of production growth relative to past trends. I test sensitivity to this by removing the calibration that constrains the model to match EIA’s 2023 projections; this increases the central global estimate from 1.2 to 2.1 GtCO2e. However, this unconstrained modeling exercise yields very large projected federal production growth under the BAU, averaging 3 million barrels per day (mb/d) of new federal oil production and 16 billion cubic feet per day (Bcf/d) of new gas production over 2024–50, levels that may be implausibly high. For reference, total federal onshore production in 2023 amounted to 1.5 mb/d for oil and 11 Bcf/d for gas. In the central analysis, by contrast, new federal production averages 1.8 mb/d for oil and 9 Bcf/d for gas. Thus this sensitivity analysis is on the very high end of plausible federal production levels and emissions impacts.

Second, natural gas production could partially displace both higher-emitting fuels like coal and lower-emitting or zero-carbon sources, creating uncertainty in the carbon intensity. All my analyses assume that 2.3 percent of gross gas production is lost as methane directly into the atmosphere (Alvarez et al. 2018) and that all incremental gas consumption (net of leakage to other sources of gas supply) represents either additional energy consumption or a one-to-one displacement of zero-carbon energy, in which case the incremental gas consumption’s complete life-cycle emissions are fully additional. I consider three alternative sensitivity analyses to this approach: (1) I change the assumed methane loss rate from 2.3 to 0 percent as a bounding exercise; because in the base case, non-combustion-related emissions from natural gas account for 9% of the overall 1.2 GtCO2e global emissions estimate, this change reduces only modestly to 1.1 GtCO2 (analogously, doubling the assumed methane loss rate would have a conceptually similar effect of increasing the central emissions estimate to about 1.3 GtCO2e). (2) I show only the emissions deriving from the additional federal oil production and entirely ignore the gas emissions (from both methane losses and gas combustion), which reduces the central global estimate to 0.7 GtCO2e. (3) I adjust the gas emissions factor to account for the mix of resources that gas may displace, in line with the approach taken in a sensitivity analysis done in Prest (2022) (see Appendix A for details). This sensitivity analysis yields a global estimate of 0.9 GtCO2e. One reason for the relatively modest changes here is that only 44 percent of the emissions impact in the central case is driven by gas production.

Third, I test the sensitivity to the central 57 percent leakage rate from Prest et al. (2024), who present a 95 percent range of leakage rates of approximately 36 to 79 percent. Using those extreme bounds in place of the central 57 percent value changes the central global 1.2 GtCO2e value to 0.6 and 1.7 GtCO2e for the high and low leakage rates, respectively.

This analysis suggests that expanding oil and gas leasing on federal lands in perpetuity to the peak rates observed over the last decade could increase global greenhouse gas emissions by about 1.2 GtCO2e from 2024 to 2050. Achieving such levels of leasing would not require further legislation but could be achieved purely through authorities currently available to the executive branch. While there is uncertainty in this estimate along several dimensions—future oil and gas prices, appropriate baselines, the emissions intensity of energy displaced by gas, and leakage rates—sensitivity analyses of these drivers suggest that the emissions impact of substantially expanded leasing on federal lands is highly unlikely to be outside the 0.6 to 2.1 GtCO2e range. In the context of legislative efforts to reform the permitting process for energy infrastructure, a natural question is to what extent a given proposal would put the federal government on such a sustained leasing pathway.

There are three primary provisions related to onshore oil and gas in the Energy Permitting Reform Act of 2024 that could be expected to have implications for emissions. Under existing statute, the Bureau of Land Management is prohibited from issuing rights-of-way for renewable energy development on federal land unless in the last year it has offered for sale 2 million acres or 50 percent of the acreage for which expressions of interest have been submitted (i.e., nominated), whichever is smaller. Section 201 of EPRA would amend this requirement such that the specific parcels offered for lease must come from within nominated parcels. EPRA would not change the overall amount of acreage required to be offered for lease, which would remain at the level set by the IRA. Estimating the net effect of Section 201 on emissions is highly uncertain given that it would depend on the behavior of firms nominating parcels (i.e. whether they nominated more or fewer parcels as a result of the provision) as well as on the specific characteristics of the nominated parcels themselves. In general, it is highly unlikely that this provision would drive the same degree of emissions increases envisioned by the high leasing scenario analyzed here.

Section 202 of EPRA would extend the term of drilling permits on federal lands from two to four years, which is unlikely to have major long-term implications for oil and gas production. Finally, section 203 of EPRA would eliminate the requirement that operators obtain federal permits to drill a well if the federal government owns less than half of the well’s minerals or if the wellbore originates on non-federal lands but passes through federally owned minerals. Such changes would not eliminate requirements for operators to obtain federal leases or state or tribal drilling permits. While such changes would provide operators with somewhat easier access to federal oil and gas, these provisions alone are unlikely to lead to millions of additional acres leased annually as modeled in this issue brief. Thus, the emissions consequences of these particular provisions are expected to be of a substantially smaller magnitude than the estimates provided here. For all of these reasons, this analysis should be considered a high upper bound on the emissions driven by these three provisions related to onshore oil and gas in EPRA, with expectations that the actual emissions effects would be lower.