Quantifying Supply-Side Climate Policies

This paper asks three questions about supply-side climate policies in the oil market: how do oil companies respond to production-based taxes; what are the aggregate effects of such taxes on global CO2 emissions; and what are the distributional consequences across consumers, producers, and governments? The study addresses a gap in empirical evidence at a time when supply-side restrictions on fossil fuel production are gaining policy traction but the quantitative literature remains limited.

The authors use proprietary company-level data from Rystad Energy’s UCube database covering 49,023 oil assets across 84 countries representing 98.1% of global oil production from 2000 to 2019. They identify 84 production tax reforms (54 increases, 30 decreases) with an average magnitude of roughly 5–6 percentage points. The empirical strategy is a difference-in-differences design that compares a company’s activity in a treated tax regime before and after a reform to the same company’s activity in other regimes over the same period, absorbing company-tax regime fixed effects, company-year fixed effects, and region-year fixed effects. This within-company cross-border comparison is used to test for, and rule out, activity-shifting spillovers. Two-stage least squares instruments the after-tax oil price with production taxes to isolate tax-driven price variation.

The primary behavioral margin is exploration: a one-percentage-point increase in the production tax rate reduces exploration expenditure by 2.6% on average over the study period, growing to 4.1% beyond five years. The elasticity of exploration with respect to the after-tax oil price is 1.96. Reduced exploration translates into fewer discoveries; a one-percentage-point tax increase reduces discovered oil amounts by 4.3% on average and by 8.9% beyond five years. The authors find no statistically significant effect of taxes on production from existing conventional fields, consistent with high adjustment costs for already-producing wells. Unconventional production (shale, oil sands, tar sands) exhibits a statistically significant intensive-margin production response to taxes. Taxes also have no detectable effect on the extraction cost of newly discovered deposits, indicating that firms do not redirect search toward lower- or higher-cost deposits at the margin.

Translating these firm-level responses into market outcomes, the authors build a dynamic field-level model spanning 2020–2100, combining field-by-field production profiles calibrated from Rystad data with demand elasticities of −0.2 and −0.5 drawn from the literature. The existing average production-weighted royalty of 21% already implies an indirect carbon price of approximately $32/tCO2 at a reference oil price of $65/barrel, an order of magnitude above the current global average demand-side carbon price of $3.1/tCO2.

Under a permanent global climate royalty surcharge of 20 percentage points, annual emissions from oil fall by 5–7% in the first five years and by 9–20% in the medium term (by year 2100). The cumulative reduction over 2020–2100 is 85–161 GtCO2, or 1.0–2.0 GtCO2 per year on average. The oil price rises by $8–14/bbl initially and by $23–27/bbl by year 2100. Tax revenue to oil-producing governments increases by $590–870 billion per year; consumer surplus falls by roughly $500–730 billion per year; producer surplus falls by $270–310 billion per year. The policy breaks even in direct economic terms at a social cost of carbon of $72–84/tCO2.

When the surcharge is adopted only by OECD countries (30% of current production, 49% of global exploration), short-term carbon leakage is 16–37%, rising to 58–82% by year 2100 as non-OECD producers increase exploration and development in response to the higher oil price. Net cumulative global emission reductions under the OECD-only scenario are 54–107 GtCO2 (47–73% of what the OECD reduction alone would achieve), roughly two-thirds of the global scenario outcome.

Q: What is the primary behavioral margin through which oil companies respond to production taxes? A: The primary margin is exploration expenditure. A one-percentage-point increase in the production tax rate reduces exploration by 2.6% on average across the study period, growing to 4.1% in the period six to twenty years after the reform. The after-tax oil price elasticity of exploration is 1.96, meaning a 1% increase in the after-tax price raises exploration by approximately 2%. The Poisson regression, which accounts for firms with zero exploration in a regime, yields consistent results, indicating the finding is not driven by firm entry or exit.

Q: Do production taxes affect output from existing oil wells? A: For conventional oil fields, the production response is statistically indistinguishable from zero across all specifications and time horizons, consistent with high adjustment costs making already-producing conventional wells insensitive to tax-driven price changes. Unconventional production (shale oil, oil sands, tar sands, extra heavy oil) is the exception, exhibiting a statistically significant intensive-margin production response to taxes. This asymmetry aligns with Bjørnland et al. (2021), who find that unconventional production is more price-sensitive than conventional production.

Q: Do taxes affect the cost profile of newly discovered deposits? A: No. The paper finds no statistically significant effect of production tax changes on the extraction cost of newly discovered fields, across all specifications and time horizons. This implies that, at the margin, firms do not redirect exploration toward lower-cost or higher-cost deposits in response to taxes; the volume and cost distribution of new discoveries are therefore treated as invariant to the tax regime in the quantitative model.

Q: How does the paper address potential activity-shifting spillovers across countries? A: The paper directly tests for spillovers by including both the own-regime tax rate and the company’s exploration-weighted average tax rate abroad as regressors; the foreign average tax rate has no statistically significant effect on domestic exploration. The analysis is also repeated restricting to small companies operating in two or fewer countries, where spillovers would be most pronounced; the null result on spillovers holds. Dropping these small companies from the main sample leaves the primary estimates unchanged.

Q: How does the paper address the potential endogeneity of tax reforms? A: The event study plots show no statistically significant pre-trends before reforms, supporting the parallel trends assumption. The paper also finds no significant correlation between tax reforms and observable oil-sector or macroeconomic variables in the pre-period. Subsamples minimizing lobbying concerns — private (non-national) oil companies, small companies, companies without pre-existing production in the country, and non-OPEC countries — all yield similar estimates, suggesting that large incumbents’ influence over tax-setting does not drive the findings.

Q: How does the paper handle the staggered difference-in-differences design? A: To address potential bias from heterogeneous and dynamic treatment effects in a two-way fixed effects framework, the paper implements a stacked regression following Cengiz et al. (2019), constructing 18 cohort-specific datasets using never-treated countries as controls. The stacked specification yields significant effects on exploration and discoveries and null results on production and extraction costs, consistent with the main estimates. The stacked event study shows no pre-trends.

Q: What is the implicit carbon price of existing production-based oil taxes? A: At the production-weighted average royalty rate of 21% and a reference oil price of $65/bbl, the existing taxes correspond to an indirect carbon price of approximately $32/tCO2, calculated using a CO2 content of 0.43 tCO2/bbl. This figure is an order of magnitude larger than the current global average demand-side carbon price of $3.1/tCO2 (a production-weighted average including zeros for unpriced emissions). This calculation pertains only to downstream combustion emissions and excludes upstream production emissions.

Q: What are the quantified effects of a global 20-percentage-point climate royalty surcharge on emissions? A: In the first five years, the surcharge reduces annual oil-embedded emissions by 0.7–1.0 GtCO2, a 5–7% reduction. By year 2100, annual reductions reach 1.2–2.6 GtCO2, a 9–20% reduction relative to baseline. The cumulative reduction over 2020–2100 is 85–161 GtCO2 (1.0–2.0 GtCO2 per year on average), representing 17–32% of the remaining carbon budget for 1.5°C warming or 7–14% of the budget for 2°C warming. All ranges span demand elasticities of −0.2 to −0.5.

Q: What happens to the global oil price under a global supply-side surcharge? A: The immediate contraction of unconventional oil production raises the oil price by $8–14/bbl in the short term. As new exploration and field development are suppressed over time, the price effect grows, reaching $23–27/bbl by year 2100. This price increase is roughly equivalent to a global carbon price of $53–63/tCO2 levied on oil consumers in the medium term.

Q: How does the paper analyze distributional incidence under the global surcharge? A: A 20-percentage-point surcharge reduces average annual consumer surplus by $500–730 billion and producer surplus by $270–310 billion per year. Tax revenue to oil-producing governments increases by $590–870 billion per year. The net present value of the aggregate economic loss is $1,000–1,400 billion; the policy breaks even in direct welfare terms at a social cost of carbon of $72–84/tCO2. Oil-producing governments are the primary beneficiaries; both consumers and oil companies lose surplus.

Q: What is the carbon leakage rate under an OECD-only supply-side coalition? A: In the short term, leakage is 16–37%, as non-OECD unconventional producers ramp up output in response to the higher oil price. By 2050 the leakage rate rises to 41–70%. By year 2100 the coalition has reduced annual production by 9,000–9,400 million barrels while non-OECD countries have increased theirs by 5,200–7,800 million barrels, implying a terminal leakage rate of 58–82%. The net cumulative global emission reduction of 54–107 GtCO2 represents 47–73% of what the OECD reduction alone achieves, and roughly two-thirds of the global scenario.

Q: Why are the authors’ supply elasticity estimates somewhat larger than the prior literature? A: The authors offer two reasons. First, their approach captures elasticity through changes in exploration activity rather than only production or field development, a broader and more forward-looking margin. Second, they use tax-driven variation in prices rather than market-price variation; the event studies show that tax reforms produce persistent changes in tax rates and after-tax prices throughout the sample, so firms are likely responding to changes perceived as durable, which would naturally elicit larger responses than responses to short-run price fluctuations.

Q: What are the key limitations and scope conditions of the model? A: The quantification omits upstream (well-to-refinery) emissions and natural gas, meaning the estimated climate effects are conservative. The demand curve is held constant over time, abstracting from long-run substitution toward clean energy. The model does not account for depletion of low-cost reserves beyond 80 years. The empirical elasticities are estimated from tax reforms that may have been perceived as temporary, meaning permanent-policy elasticities could be larger, which would imply both larger emission reductions under a global policy and higher leakage rates under a partial coalition.

Q: How do distributional consequences differ between the OECD-only and global scenarios? A: Under the OECD-only surcharge, OECD consumers and OECD producers both lose surplus, while non-OECD producers and governments everywhere gain — non-OECD governments solely through the oil price increase without bearing any tax burden. The sum of OECD producer surplus losses and non-OECD producer surplus gains is slightly negative overall. The aggregate annual global economic loss under the OECD scenario is $120–170 billion, slightly lower than the global scenario ($130–220 billion), because the oil price increase and quantity reduction are both smaller in the OECD case.

Production-based tax (royalty): A tax levied on gross oil production or gross income from oil, not on profit. Unlike profit-based taxes, these are not deductible against costs and therefore create incentives to curtail exploration and production. In the paper’s framework they are equivalent to a supply-side climate instrument because they reduce the after-tax price received by producers.

Climate royalty surcharge: An additional production-based tax, layered on top of existing taxes, proposed as an explicit supply-side climate policy instrument. Following Prest and Stock (2023), the paper defines this as an ad valorem levy on oil production that implicitly prices downstream CO2 emissions through its effect on the after-tax oil price.

Carbon leakage: The offsetting increase in oil production by non-coalition countries in response to an oil price rise caused by a supply-restricting policy adopted by a subset of producers. Measured as the ratio of the production increase in non-coalition countries to the production reduction in coalition countries, expressed as a percentage.

After-tax oil price elasticity of exploration: The percentage change in exploration expenditure per one-percent change in the after-tax oil price, estimated via 2SLS instrumenting the after-tax price with production taxes. The preferred estimate is 1.96, implying elastic exploration responses to tax-driven price changes.

Extraction cost (breakeven price): The constant oil price at which the net present value of developing a field equals zero, computed using a real discount rate of 7.5%. It is the minimum price at which a field is commercially viable absent profit taxes. In the quantitative model, fields are developed if and only if extraction cost falls below the after-tax oil price.

Indirect carbon price: The implicit CO2 price embedded in a production-based oil tax, calculated as the ad valorem royalty rate multiplied by the oil price and divided by the CO2 content of oil. The paper calculates that the existing average 21% royalty at $65/bbl corresponds to an indirect carbon price of approximately $32/tCO2, applicable only to downstream combustion emissions.

Stacked regression (staggered DiD): A robustness approach to two-way fixed effects with staggered treatment timing, constructing cohort-specific datasets for each treatment year using only never-treated units as controls, thereby avoiding contamination from using already-treated units as comparisons for later-treated units.