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

This issue brief models the impacts of expanding oil and gas production on US federal lands.

Date

Sept. 3, 2024

Authors

Brian C. Prest

Publication

Reading time

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

Figure 1. Historical Federal Leasing and Drilling, Oil and Gas Prices, and Production

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.

Table 1. Cumulative 2024-50 Incremental Global Emissions (GtCO2e) from New Oil and Gas Production, Net of 57% Leakage

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).

Figure 2. Modeled Federal Leasing and Drilling under EIA AEO Reference Case Oil and Gas Prices

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.

Figure 3. Sensitivity Analyses of Cumulative Incremental Emissions

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.

For references and the appendices, please download the PDF using the link at the top of the page.

Topics

• Federal Climate Policy
• Industry and Fuels
• Fossil Fuels

Authors

Brian C. Prest

Fellow; Director, Social Cost of Carbon Initiative

Brian Prest is an economist and fellow at Resources for the Future specializing in climate change, oil and gas, and energy economics.

Related Content