L71 | Macro Paper Warehouse

Environmental Consequences of Hydrocarbon Infrastructure Policy

Mon, 01 Jan 0001 00:00:00 +0000

Covert and Kellogg study policies that aim to “keep carbon in the ground” by blocking fossil fuel infrastructure investment, with the Dakota Access Pipeline (DAPL) as their empirical application. DAPL moves more than 500,000 barrels per day of oil from the Bakken Shale of North Dakota to the U.S. Gulf Coast and was completed in June 2017 amid substantial opposition. The central research question is whether blocking pipeline construction actually keeps oil in the ground or merely shifts transport to alternative modes — specifically crude-by-rail — and what the net environmental and economic consequences are.

The paper develops a two-period model of crude oil production and transportation mode choice. In the model, oil shippers decide in period 1 whether to commit to pipeline capacity under ship-or-pay contracts, then in period 2 allocate flows between the committed pipeline and the more flexible but costlier railroad alternative. Pipeline construction is an irreversible sunk cost with zero ongoing marginal cost; rail involves no sunk cost but substantial ongoing marginal costs including quadratic adjustment costs that capture capital investment in rail cars and loading/unloading facilities. Equilibrium pipeline capacity is determined by a shippers’ indifference condition: expected per-barrel returns from pipeline access equal the FERC-regulated tariff.

The empirical model is estimated using monthly Bakken oil production and transportation data, price differentials across three coastal destinations (Gulf, East, West), and drilling productivity data. Crude-by-rail marginal costs are estimated via 2SLS, yielding static marginal cost intercepts of $9.49/bbl to the East Coast, $12.64/bbl to the Gulf Coast, and $8.69/bbl to the West Coast, plus a dynamic adjustment cost of $1.28/bbl per mbbl/d of flow change. The upstream supply model follows Anderson, Kellogg, and Salant (2018), with old-well production following exponential decline (estimated decay parameter β = 0.955) and new-well drilling responding to current and lagged prices with a total long-run elasticity of 1.32. Shippers’ beliefs about future oil prices are calibrated to an AR(1) process fit to historical price volatility (persistence φ₁ = 0.9925, volatility σ_G = 0.098). Model validation confirms a predicted expected return to pipeline commitment of $6.17/bbl against DAPL’s actual tariff of $5.50–$6.25/bbl.

The main counterfactual asks what would have happened had DAPL’s construction been enjoined. In expectation, blocking DAPL reduces pipeline flows by 306 mbbl/d. Expected crude-by-rail flows increase by 248 mbbl/d, offsetting 81% of the pipeline reduction. Bakken oil production falls by only 58 mbbl/d, a 4% reduction. The modal shift from pipeline to rail worsens local environmental outcomes: per-barrel local pollution damages from rail transport substantially exceed those from pipelines, dominated by locomotive NOx emissions in populated areas. Foreclosing DAPL increases net local pollution damages by $444,000 per day (the decrease in pipeline-related harm of $144,000/day is more than offset by the increase from rail of $588,000/day). The total cost of blocking DAPL is $45/tonne of CO2 abated — $28/tonne from lost producer surplus and $17/tonne from increased local pollution damages — a figure comparable to the contemporaneous U.S. government social cost of carbon estimate of $42/tonne.

An upstream production tax achieving the same CO2 reduction costs only $1.01–$2.68/tonne CO2 abated, an order of magnitude less, because it does not induce the distortionary modal shift to rail. Two caveats apply: if 57% of Bakken production reductions leak to other basins, the cost of blocking DAPL rises from $45/tonne to $104/tonne; and if reductions represent production delays rather than permanent reductions, effective abatement is further diminished. The analysis is scoped to Bakken crude oil and land transportation alternatives. The finding that blocking infrastructure increases local pollution is atypical of CO2 abatement policies, which usually generate local pollution co-benefits.

Q: What is the core economic mechanism by which blocking a pipeline can keep oil in the ground? A: When a pipeline is foreclosed, crude oil can still move by railroad, but rail transport involves substantial ongoing marginal costs. These costs create a wedge between upstream (Bakken) and downstream (Gulf Coast) prices that depresses upstream supply. Only when downstream prices are high enough to cover both rail marginal cost and this wedge will rail fully substitute for the pipeline; at lower prices, some production is uneconomical and stays in the ground. In the model, this price-depressing wedge is the mechanism that reduces production — but it operates only partially, since rail can substitute for much of the pipeline’s flow.

Q: How much of the blocked pipeline flow substitutes to rail versus stays in the ground? A: In expectation, blocking DAPL reduces pipeline flows by 306 mbbl/d. Expected crude-by-rail flows increase by 248 mbbl/d, offsetting 81% of the pipeline reduction. Bakken oil production falls by only 58 mbbl/d, or approximately 4%. In a specific simulated month (December 2019), 348 mbbl/d (67%) of the 520 mbbl/d of foregone pipeline flows would still move by rail.

Q: How are crude-by-rail costs estimated, and what is the role of adjustment costs? A: The authors estimate a 2SLS model of rail flows on price differentials, allowing for quadratic adjustment costs to capture investments and disinvestments in rail cars and loading facilities. Static marginal costs are $9.49/bbl (East Coast), $12.64/bbl (Gulf Coast), and $8.69/bbl (West Coast). The adjustment cost parameter γ is estimated at $1.28/bbl per mbbl/d, meaning a 10 mbbl/d monthly increase in rail flows raises marginal shipping cost by $12.76/bbl — a substantial share of total rail costs. Adjustment costs are necessary to reconcile the model with the sluggish observed response of rail flows to price differentials.

Q: What is the structure of the upstream oil supply model and what are its key parameter estimates? A: The model distinguishes “old” production from pre-existing wells, which follows exponential decline with estimated decay parameter β = 0.955, and “new” production from newly drilled wells, which is price-responsive with a total long-run elasticity of 1.32 — comparable to the 1.1–1.2 estimated by Newell and Prest (2019) across major U.S. shale plays. This structure implies that total production is highly inelastic in the short run (dominated by old wells) but responds to persistent price shocks over the long run through changes in drilling rates.

Q: How do the local pollution damages of rail compare to those of pipeline transport? A: At a social cost of carbon of $100/tonne, local air pollution damages from rail transport to the Gulf Coast are $1.66/bbl (plus $0.73/bbl in spill/accident costs), versus only $0.35/bbl local pollution (plus $0.11/bbl spills) for pipelines. Locomotive NOx emissions are the dominant factor, both because locomotives have high NOx emission factors and because these emissions often occur in densely populated areas. CO2 damages at $100/tonne SCC are roughly similar across modes ($0.79–0.83/bbl), so local pollution is the key differentiator.

Q: What is the net welfare impact of foreclosing DAPL, and how is it decomposed? A: Foreclosing DAPL reduces producer surplus by $716,000/day, increases net local pollution damages by $444,000/day (the $588,000/day increase from rail more than offsets the $144,000/day decrease from pipeline), and reduces CO2 emissions by 25.2 mtonnes/day from the 58 mbbl/d production reduction. The cost per tonne of CO2 abated is $28/tonne from lost producer surplus and $17/tonne from increased local pollution damages, totaling $45/tonne — broadly comparable to the U.S. government’s contemporaneous SCC estimate of $42/tonne. This means the policy’s abatement cost is approximately equal to the social value of each tonne abated, leaving little or no net social gain even before accounting for leakage.

Q: How does the model validate against observed data and institutional parameters? A: The model predicts an expected return to committed DAPL pipeline shipment of $6.17/bbl, which closely matches the actual DAPL tariff for committed shippers of $5.50–$6.25/bbl. The authors also validate simulated crude-by-rail flows against actual flows across destinations. The close match on the tariff is particularly meaningful because it tests the model’s equilibrium condition for pipeline capacity investment rather than a within-sample fit.

Q: How does an upstream production tax compare to blocking DAPL as a policy instrument? A: A production tax normalized to achieve the same CO2 reduction requires only $3.68/bbl if imposed after shippers have committed to DAPL (holding capacity fixed), or $3.24/bbl if announced before commitments are made (reducing pipeline capacity to 443 mbbl/d). The production tax reduces combined producer surplus and government revenue by only $96,000–$109,000/day versus $716,000/day under the DAPL ban, and reduces local pollution damages by $82,000/day rather than increasing them. The resulting cost per tonne CO2 abated is $1.01–$2.68 — an order of magnitude smaller than the $44.63/tonne for blocking DAPL.

Q: What is the production leakage caveat and how large is its effect? A: If blocking DAPL causes Bakken production to fall, production from other U.S. or global oil basins may increase, partially or fully offsetting the CO2 reduction. Following Prest (2022) and Prest et al. (2023), the authors note that if 57% of the Bakken production reduction leaks to other basins, the cost of blocking DAPL rises from $45/tonne to $104/tonne. Leakage would increase the cost per tonne for the upstream tax as well, but the relative advantage of the tax over the pipeline ban is unaffected by this caveat.

Q: What is the production delay caveat? A: Even absent leakage, the paper cautions that production reductions from either policy may represent production delays rather than permanent reductions — oil not extracted today may be extracted later as prices rise or technology improves. To the extent that reductions are temporary, the effective carbon abatement is smaller than the authors compute, and the cost per tonne of CO2 abated is correspondingly higher. The paper does not quantify this effect but flags it as a material caveat.

Q: What institutional features drive pipeline capacity investment and risk allocation? A: Pipelines are irreversible investments subject to ex-post holdup, so construction financing requires firm ship-or-pay commitments from shippers before construction and before future prices are known, meaning oil price risk is borne primarily by shippers rather than the pipeline owner. Pipeline tariffs are regulated by FERC on a cost-of-service basis. In the DAPL case, shippers executed binding ten-year ship-or-pay contracts in June 2014, and shippers’ beliefs about future oil prices at that date — calibrated to historical price volatility using an AR(1) process with estimated persistence φ₁ = 0.9925 and volatility σ_G = 0.098 — determine equilibrium capacity investment.

Q: How does the paper’s finding relate to the typical co-benefit structure of climate policies? A: Most CO2 abatement policies generate local pollution co-benefits (reduced NOx, SOx, particulates), so the abatement cost is partially offset by local pollution gains. Blocking DAPL reverses this: the pipeline-to-rail modal shift increases local pollution damages, making local pollution a cost rather than a co-benefit of the policy. The authors note this is atypical but not unprecedented — urban densification and post-combustion emissions controls in fossil fuel boilers also present CO2–local pollution trade-offs.

Infrastructure foreclosure policy: A “keep it in the ground” strategy that blocks construction of specialized fossil fuel transportation infrastructure (pipelines) with the aim of inhibiting production of the fuels that would have been transported, without requiring direct acquisition or buyout of mineral rights.
Ship-or-pay agreement: A firm, up-front capacity commitment in which a pipeline shipper agrees to pay for reserved pipeline capacity whether or not they ultimately use it, made before construction and before future prices are realized; the institutional mechanism by which oil price risk is transferred from pipeline owners to shippers.
Crude-by-rail adjustment costs: Quadratic costs modeled as linear in the period-to-period change in rail volumes to a given destination, capturing capital investments and disinvestments in rail cars, loading facilities, and unloading terminals needed to expand or contract crude-by-rail capacity; estimated at $1.28/bbl per mbbl/d of monthly flow change.
Production leakage: The partial or full offset of production reductions in one oil basin (Bakken) by production increases in other U.S. or global basins in response to the same price signals; at 57% leakage, the cost of blocking DAPL rises from $45/tonne to $104/tonne of CO2 abated.
Old-well vs. new-well production dynamics: The distinction between production from pre-existing wells (which follows an exponential decline path insensitive to current prices, β = 0.955) and production from newly drilled wells (which responds to current and lagged upstream prices with long-run elasticity 1.32); this structure makes total short-run supply highly inelastic while allowing substantial long-run price responsiveness through drilling adjustments.
Local pollution damages from NOx: The dominant component of environmental harm from crude-by-rail transport, arising from locomotive NOx emissions that are both large in magnitude and concentrated in densely populated areas along rail corridors; at $100/tonne SCC, monetized local pollution damages from rail exceed CO2 damages for all three coastal destinations, whereas for pipelines CO2 damages exceed local pollution costs.
Cost per tonne of CO2 abated: The authors’ metric for comparing infrastructure foreclosure to alternative policies; computed as the sum of lost producer surplus and net change in local pollution damages divided by the quantity of CO2 emissions avoided from reduced oil production and consumption; equals $45/tonne for blocking DAPL versus $1.01–$2.68/tonne for an equivalent upstream production tax.

Quantifying Supply-Side Climate Policies

Mon, 01 Jan 0001 00:00:00 +0000

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.