Fossil fuel subsidies in the Permian remain pervasive and should be eliminated

The Permian Basin leads US oil production by a large margin and is the second-largest natural gas producing basin in the country.  Production reached an all-time high of 5.8 mbpd in 2023, "out-producing even Saudi Arabia’s massive Ghawar oilfield."  The economics of the region are strong, with more than $100 billion in mergers and acquisitions last year, and shale output that "is highly productive with large undeveloped reserves and robust infrastructure."  This is hardly the market environment that calls for government subsidies; and yet subsidies there are. Some have been around for a century, many for decades, and new subsidies continue to be added. 

And against this backdrop there is a well-recognized need to decarbonize the global economy -- as well as national commitments that call out subsidy removal as a way to do so. For example, the G7 Leader's Declaration, issued at the conclusion of the 2016 Ise-Shima Summit in Japan, contained a timeline for removing fossil fuel subsidies: 

Given the fact that energy production and use account for around two-thirds of global GHG emissions, we recognize the crucial role that the energy sector has to play in combatting climate change. We remain committed to the elimination of inefficient fossil fuel subsidies and encourage all countries to do so by 2025. 

As the largest economy within the G7, that statement clearly applies to the United States. Unfortunately, while the 2025 deadline is rapidly approaching, subsidy elimination is not. Our mapping of Permian subsidies (Fossilized Finances: Oil and Gas Subsidies in the Permian Basin, prepared with the Natural Resources Defense Council) provides many useful places to move subsidy reform forward. Highlights from, and discussions of, our findings are in this article; the full report can be accessed at the link below.

Report: Fossilized Finances: Oil and Gas Subsidies in the Permian Basin 

Texas High Cost Well Subsidy (Texas)

The Texas High Cost Well subsidy offers a reduced severance tax rate for selected natural gas wells for 10 years, or until the well accumulates tax savings that total 50 percent of its drilling and completion costs. The Texas Railroad Commission defines "high-cost natural gas" as natural gas that is produced from a well deeper than 15,000 feet using certain types of production methods.  There is no requirement that wells be unprofitable in order to receive this benefit. Similarly, improvements in the cost-efficiency of wells meeting these criteria as a group will not result in the subsidy being reduced or removed. 

This subsidy will cost Texas taxpayers approximately $6.3 billion between 2023 and 2028.  It has been in place for much longer: state data suggest revenues losses of $17.1 billion between 2009 and 2028.  Cost transparency on the provision has been an issue as well: arcane rules on tax expenditure reporting in Texas have resulted in the cost to taxpayers from the High Cost Well provision being left out of some editions of the state's primary information source on tax expenditures, the biennial Tax Exemptions & Tax Incidence Report. See more on the cost and transparency issues around this tax break here and here.

Natural Gas Transportation and Processing Deduction (New Mexico)

New Mexico’s Oil and Gas Emergency School Tax was imposed in 1959 for the “privilege of engaging in the business of severing oil, natural gas or liquid hydrocarbons, and carbon dioxide from New Mexico soil.” The rate for natural gas is 4 percent, but to offset the risks of fossil fuel exploration the state has allowed deductions to this tax for the cost of “reasonable expenses” either to process natural gas so it is ready for sale or to truck oil to the first place of market.  In both of these cases, there is an incentive for producers to inflate processing and transport costs since this reduces the extraction taxes and royalties due. 

This type of gaming is a risk because the "sale price" is not a clear-cut value and policing how it is calculated is both important and challenging. Where products are transferred to related parties without "arms-length" market prices, accurate valuation is particularly difficult. While this issue is not unique to New Mexico, they allow more extensive cost deductions from the taxable base than many other oil and gas producing states.  

New Mexico's Taxation & Revenue Department monitors changes in taxes paid from prior years and researches large disparities; however, it doesn't conduct a formal review of claims.  Data reported on NM's form ACD-31114 could allow some analysis of deductions across taxpayers, though does not differentiate transfers to affiliates from sales to third parties.  

Researchers at the University of Chicago analyzed the valuation challenges regarding royalties on federal oil and gas leases, noting that "firms currently enjoy tremendous flexibility in how they price oil and gas sales and take allowable cost deductions for the purpose of royalty valuation...All of these choices and more allow firms to select terms that are most favorable to them, at the expense of U.S. taxpayers." While their analysis applied to royalties rather than extraction taxes, the issues are similar. And they suggested an effective solution would be simply eliminating these deductions from the royalty base.  

Between 2018 and 2022 the natural gas processing deductions cost NM state taxpayers $268 million. Although deductions for oil transport and processing are not included in the tax expenditure budget, it is likely that similar valuation challenges apply. Both areas should be analyzed in much more detail given the importance of fuel tax and royalty revenues to the state. For FY 2023, NM raised $2.17 billion from oil and gas severance taxes and another $3.19 billion from the state share of federal oil and gas royalties; these were among their largest sources of revenue.  Expanded auditing of deductions, benchmarking to levels in other states, and reducing the range of costs that can be deducted would all be worthwhile strategies for the state to pursue.

Abandoned Oil and Gas Wells (Federal, Texas, and New Mexico)

Many thousands of dormant or unproductive oil and gas wells are found across the Permian Basin. Without proper plugging, these wells can pollute the surrounding land, air, and water with leaked toxins, including uncontrolled methane. Despite state and federal requirements that fossil fuel companies properly shut down their wells when production is completed, many declare bankruptcy instead, effectively shifting the cost of cleanup to taxpayers. Requirements to hold bonds that would prevent such cost shifting in the event of bankruptcy are set far too low at both the federal and state levels. State well plugging funds, often funded by taxes on industry, help a bit. But collections are also well below the amounts needed to properly close the abandoned sites. 

Although Texas does not release data on bond coverage ratios for existing wells, data on surety bonds in New Mexico demonstrate the scale of the problem. With a face value of less than 1 percent of estimated closure costs, it seems likely that the public will end up footing a large portion of the cleanup bill.  The estimated cost to plug and abandon all currently operating wells in New Mexico and Texas could reach $110 billion.  

Well closure is a predictable cost of oil and gas operations. The costs are supposed to be funded by well operators and owners, or in the case of defunct operators, via surety bonds and state orphan well funds. Too often, these costs are being dumped on to taxpayers instead. The Bipartisan Infrastructure Law, for example, provided $4.7 billion in federal money to supplement other funding sources.TX estimates it will receive $344m of this amount.  NM estimates it will receive $44m.  The funds should come from oil and gas producers within the state, not from state or federal taxpayers. Further, the higher premiums associated with procuring proper bonding levels would have the added benefit of encouraging better site management to reduce insurance costs.

Government-provided hedges against low oil and gas prices

A variety of holidays from, or reductions in, state taxes and fees are implemented in both states and the federal tax code when well production declines (marginal or stripper wells), to restart idled or orphaned wells, or to use enhanced recovery methods. Examples in New Mexico include a reduction in the oil and gas emergency school tax or severance tax in low price environments for stripper wells, well restarts or workovers, or the adoption of enhanced recovery methods. Texas also reduces taxes for marginal oil and gas wells during low price periods, as does the federal government for enhanced oil recovery. 

At first glance, subsidies in low price environments appear to have some logic. By reducing the state charges when product prices decline, maybe wells can continue producing for longer in the face of worsening market conditions. 

Once one applies a broader market view, however, it is clear that these policies should be ended. First, all industries go through macro-related pricing cycles. All face competitive challenges from rising costs as capital ages and productivity drops, or from more efficient new entrants. All industries face changing demand for their products due to shifts in consumer needs or demand. Yet, the government doesn't cut out fees in those other sectors. Rather, firms need to manage these risks internally through process improvements, research and development, and improved efficiency. 

Second, subsidies with price triggers can seem costless when oil and gas prices are relatively high (as they are now), but they are not. In these environments, tax expenditure budgets include the provisions and estimate their cost in terms of lost revenue to the state at zero. Despite these optics, it is important to recognize that even now -- and despite a zero value in tax expenditure budgets -- the provisions remain subsidies and are distorting the market. By shifting down-side market risk to taxpayers, the share of investment risks borne by the private owners of the wells, and likely their cost of capital for new investment as well, both decline. This benefits investors and owners via a reduced breakeven for new investments in oil and gas relative to what would exist absent the subsidies. Since the economy needs to reduce carbon emissions, these types of subsidies don't make sense. 

In addition, hedging to protect against price declines is already available in the private sector, albeit not for free like with the government programs. Indeed, the private cost to hedge is incurred whether or not prices end up dropping as feared. The key point is that if oil and gas producers highly value the down-side market protections they obtain through these subsidies, they could hedge these risks directly in the options market. Some of this already happens with both producers and large purchasers (such as airlines). The "hedge ratio" is a metric of how widely price risks are being hedged by industry. As of mid-2023, for example, hedge ratios for oil nationally were just above 21%, considered low. At the time, only 5% of 2024 output was hedged. Hedge rates for natural gas were higher, 43.2% for 2023 and 22.5% for 2024.  The author notes that natural gas had more recent price crashes, which may drive their higher hedge rate.  Were subsidies to producers in low price environments to be removed, producers could alter their hedging ratios to adjust.  This approach would ensure that the risks are borne by the private producer rather than the taxpayer, and the cost of hedging that risk flows through market prices for oil and gas. Both outcomes are beneficial.

Where politics prevents the elimination of down-side price protection subsidies, the governments should at least receive a higher-than-baseline tax or fee during periods of high prices.

An important side-note is that governments, including in the Permian, often have similar subsidies but with no price phase-outs. This means that subsidies are granted even in high priced markets, effectively padding producer profits. In Texas, these include subsidies to the restart of orphaned wells or wells inactive more more than two years; low production wells that use energy efficient production equipment; a permanent severance tax exemption for capturing and marketing casinghead gas that had previously been vented or flared; and for enhanced oil recovery techniques, with supplemental tax reductions if anthropogenic CO₂ is used as an injectant. Subsidies that phase out as oil and gas prices rise are at least a better structure for taxpayers. 

Emerging Subsidies

Political pressure for new policies supporting fossil fuels are always present. Too often this results in new subsidies rather than subsidy reform or elimination. This dynamic makes achieving significant net subsidy reductions even more challenging. A few examples affecting the Permian warrant mention, as they are potentially quite large.

New investment property tax credits (Texas)

Property tax credits aimed at job creation from new investments are awarded to upstream oil and gas investments, refineries, gas processing, liquid natural gas and manufacturers of extraction equipment, and chemical plants reliant on fossil fuel feedstocks.  These sectors received at least half of the $10.8 billion in such tax credits through 2022 under the predecessor tax exemption, Chapter 313, which expired in 2022.   Interestingly, Chapter 313 reporting included separate categories for wind and non-wind renewables. However, projects related to oil and gas were not separately tabulated, but rather grouped as "manufacturing" making the industry linkage less visible. 

While Chapter 313 allowed eligibility for renewables, the replacement tax credit under Chapter 403 does not. Projects related to oil and gas remain eligible.  

Texas Energy Fund

Passed by referendum in November 2023, Proposition 7 created a $10 billion fund to increase grid reliability in Texas with a stated goal of addressing serious grid failures in 2021 that resulted in the death of more than 200 people. Of this amount, $7.2 billion is allocated for dispatchable power generation infrastructure. While theoretically available to nuclear and coal, this program is widely understood to fund new natural gas plants.  Utility-scale batteries are dispatchable and can efficiently boost reliability in many cases, but are not eligible. Nor are other strategies on the demand side or increased grid interconnects.

Carbon capture and sequestration

Many new policies, particularly at the federal level, aim to subsidize the costs of carbon capture and sequestration. Approaches include direct grants, cost sharing, and large tax credits, such as the Section 45Q credit for CCS that was greatly expanded in the Inflation Reduction Act. Shifting the responsibility for the risks of failed sequestration projects from owners to taxpayers is another emerging venue of subsidization. The liability periods for failed projects and recapture of credits claimed appear to be much shorter than the project duration in many jurisdictions. 

This is an area requiring a great deal of monitoring and additional research. However, in any scenario it is likely that a substantial portion of these subsidies will flow to firms and projects in the Permian. Indeed, modeling by Princeton University suggests that the largest and least-expensive sites for storing captured carbon are adjacent to the Permian. Their assessments suggest that the Gulf Coast may provide about 75% of the US total sequestration capacity, initially fed mostly from the Permian though adding other regions as CO2 pipeline capacity is built out. New CO2 pipelines are estimated to require investment of $170 to $230b.  Storage costs for basins in TX and the Gulf Coast were estimated to be the least expensive in the country by the Princeton team.  Plans for a Gulf Coast carbon storage hub have been floated by Exxon with a projected cost of $100 billion, which they propose be met through an (unspecified) mix of public and private funding. 

With carbon prices, the costs to control emissions from fossil fuel extraction and carbon-intensive industries would be reflected in the pricing of the resultant products. Those price signals would align with decarbonization goals and support substitute products with a lower carbon footprint. Under the current policy mix, CO₂ instead will have a monetary value from the subsidies. The details of how this will affect investment decisions and operational management of existing assets is unclear. However, it is likely that some older, high-carbon facilities may remain open longer or be utilized more intensively; and that drilling in marginal wells with higher CO₂ content may now be economic. Entry of alternative products will occur more slowly than would have been the case in a no-subsidy baseline.