State and Local Permitting Restrictions on Oil and Gas
Introduction
Despite rising growth in renewable energy, the oil and gas sector continues to play a significant role in the U.S. economy—especially for electricity generation and transportation. Natural gas was the largest source of power in 2023, accounting for 43 percent of generation. Demand for these energy sources is potentially increasing in the United States and among foreign customers who seek to purchase U.S.-produced oil and gas, which is elevating demand for related infrastructure. Importantly, infrastructure needs increase with peak oil- and gas-demand growth even if total consumption declines. Thus, although oil generates only 0.4 percent of our nation’s power, its availability is critical given that consumption typically occurs when the grid is highly stressed.
The domestic oil and gas industry faces myriad permitting and siting restrictions, which will have a continued (and perhaps increasingly negative) impact on the availability and cost of oil and gas in U.S. markets. In this piece, we focus on state-level barriers to oil and gas infrastructure development to the extent that they affect power generation, namely natural gas pipelines; natural gas and oil-fired power plants; and carbon capture, utilization, and storage (CCUS). While we did perform data analysis on oil pipelines, the findings were so similar to our natural gas assessment that we excluded them for brevity’s sake. Broadly, we found the stringency of oil and gas infrastructure permitting to be heterogeneous across states, indicating that the negative economic effects of insufficient infrastructure will be disparate across the country.
Examining Pipeline Data
Assessing a capacity deficiency in available data is challenging because data for a counterfactual does not exist (i.e., there is no data for fuel deliveries that never occurred). Therefore, we must determine whether data exists to support common anecdotal claims about pipeline deficiency.
The recent growth in demand for natural gas is an effective example for determining state-level permitting constraints for pipelines. The following chart, based on data from the U.S. Energy Information Administration (EIA) Natural Gas Pipeline Projects Database, shows cumulative additional pipeline capacity for natural gas transmission by year, highlighting a linear trend that does not indicate a problem in and of itself.
However, when examining completed pipeline projects broken down by permitting authority, we see that few major natural gas pipeline projects have been completed in recent years. Importantly, although states used to approve a relatively large share of natural gas pipeline, most recent projects have fallen under the jurisdiction of the Federal Energy Regulatory Commission (FERC).
But when we look at the EIA data on cumulative additional capacity in another way—by state—we see a different picture with regard to the national trend of largely linear increases in natural gas pipeline capacity. The following chart examines key states in oil and gas consumption and production. Some make outsized contributions to the national data—particularly Texas.
Excluding Texas from the data, we gain even more insight. We can see increases in the cumulative capacity of natural gas pipelines in some states with large increases in natural gas production, like Pennsylvania. Meanwhile, states with policies that restrict pipeline development—such as California, Massachusetts, and New York—have barely approved any new pipelines in recent years.
In the natural gas sector, we see that even though consumption is rising and overall pipeline capacity is increasing on a national level, some states have lower-than-expected pipeline growth. Electricity system operators in California, New York, and Massachusetts have explicitly acknowledged deficiencies in available natural gas infrastructure, indicating an artificial reason for the disconnect between expected demand and pipeline growth in those states.
One likely explanation is that residents of states that produce little natural gas see more risk than value in new pipelines, even when the state consumes a lot of natural gas. Although many pipeline projects are under the authority of FERC, states still have a major role in determining local air- and water-quality regulations, which raise the cost of and make it more difficult to permit projects. As an example, while Section 401 of the Clean Water Act defers an essential portion of pipeline permitting to states, New York’s refusal to issue such permits for pipelines has effectively prohibited new pipeline construction in the state and negated expansion to downstream natural gas customers in New England. The reality is that if state governments do not want to approve pipelines, those pipelines cannot be built.
Findings
Our data analysis confirms that, despite having similar processes for pipeline approval across the country, some states are simply more restrictive in issuing permits required for new pipelines. Additionally, states that produce oil and gas are far more likely to add pipeline capacity than those that do not. This would not be noteworthy in and of itself, except that we see large demand for gas in non-producing states along with economic challenges caused by constrained oil and gas infrastructure. The fact that the market is not operating as expected indicates that some states have made it more difficult to build pipelines for non-economic reasons.
Locational economic effects exacerbated by pipeline access deficiency further reinforce the observed dynamic of pipeline restriction in select states. For example, despite being poorly suited to gas pipeline alternatives, many northeastern states have heightened pipeline restrictions, resulting in pronounced economic costs and reliability risk. Pipeline constraints cause steep winter natural gas price premiums in these states relative to the Henry Hub basis, which in turn increases electricity prices. From a reliability perspective, the Northeast faces chronic elevated power plant outage risk from natural gas power plants that, lacking firm pipeline service, resort to less-reliable liquefied natural gas import deliveries. Regional efforts to reduce gas consumption do not necessarily offset pipeline needs because converting some end-uses from gas to electricity may not reduce peak gas demand. A severe winter storm in December 2022 demonstrated the consequences of insufficient pipeline service. Pipeline pressure loss in New York State nearly led to an unprecedented loss of the entire Con Edison system, which could have taken months to restore.
Discrepancies in State Permitting for Oil and Gas Power Plants
It is difficult to attribute differences in oil and gas plant development to state permitting and siting policies, but gaps between commercial activity and economic expectations serve as a rough proxy. The permitting climate for gas plants was generally favorable in the 2010s, with an inflection point in the early 2020s as some states began issuing more selective or blanket denials of gas plants—both new projects and those aimed at repowering existing facilities. Given long lead times to develop power plants, the effects of these recent permitting law trends are best observed in changes to planned generation.
Interconnection request trends signify the level of planned generation development that, in part, reflects state permitting and siting restrictions. For example, the western United States has seen sustained natural gas generation interest—except for California, which has called for no new gas plant permitting in the state. In Texas and the Mid-Atlantic, natural gas went from being the predominant fuel class seeking interconnection in the mid-2010s to being overrun by renewables and storage. This may reflect competitive electricity markets in those regions, which accelerated the coal-to-gas transition last decade and the renewables transition this decade. Nevertheless, oil and gas generation permitting restrictions increased over the last 10 years in the Mid-Atlantic. The Southeast retained the most robust planned gas generation, consistent with the region’s cost-of-service generation and relatively low gas permitting barriers. The Great Plains and the Midwest do not display a clear trend.
The last five years indicate that commercial interest in natural gas expansion has dropped precipitously in the Northeast, with some variance within New England states. This is due in part to the effects of permit denials restricting gas pipeline expansion, which reduces fuel access and increases fuel costs to new gas plants. It also results directly from various cases of regulatory denial and organized resistance in power plant permitting and siting.
Permitting for oil generation is most important when it provides backup, or fuel-switching, capabilities at plants typically operating on natural gas. The tighter the restrictions on gas pipelines, the greater the ongoing reliance on backup oil. Permitting can restrict the operation of plants running on oil by reducing the amount of on-site oil inventory at a plant as well as establishing combustion limits.
Power grid cost and reliability are especially sensitive to these permitting factors. In the Northeast, for example, tighter air permitting has triggered oil and gas generator retirement announcements. Some of these would induce violations of regional reliability criteria, compelling grid operators to order units to stay online for reliability purposes. This has been most evident in California and the Northeast. Importantly, grid operators’ ability to compensate “reliability must-run” plants to stay online may not always supersede state permitting authorities. Further, no such reliability mechanism exists to overcome the permitting and siting of new generation, which may prove especially problematic with the return of load growth. As permitting pressures tighten, particularly in the Northeast, forcing uneconomic retirements of gas and oil generation or inhibiting sufficient natural gas supply to power plants will exacerbate reliability risk in the near-term and create supply deficiencies by the late 2020s.
Carbon Capture Utilization and Storage (CCUS)
Issues related to permitting in the oil and gas sector are also raising concerns that climate-related technologies aimed at decarbonizing oil and gas—namely CCUS—could be similarly affected. Although there is only one commercially operating carbon capture power plant and a second planned for the future, climate target pathways require significant increases in CCUS uptake, and recent modifications to CCUS subsidies under the Inflation Reduction Act will likely drive greater adoption.
There are two fundamental issues related to CCUS and state-level permitting. The first is the need for carbon dioxide (CO2) pipelines, which can carry CO2 from the anthropogenic source (e.g., a power plant) to its sequestration or utilization point, such as an oil well utilizing enhanced oil recovery. The second is permitting of the injection site (likely a well).
When it comes to CO2 pipeline projects, all normal considerations for oil and gas pipelines apply, but CO2 pipelines face distinct challenges because, even though they are energy-related, they may not be eligible for the same eminent domain privileges as other linear infrastructure. Consequently, CO2 pipelines are primarily permitted by states, meaning they face state-level opposition. This introduces a challenge because a CO2 pipeline rupture in Mississippi has motivated state-level opposition to such projects. California, for example, has enacted a moratorium on CO2 pipelines, and Illinois is considering one of its own. As observed with other permitting issues, a “not-in-my-backyard” sentiment can stymie pipeline growth.
Wells present a more readily addressable problem. In the oil and gas industry, the federal government permits wells on federal land; states usually issue other drilling permits. Because multiple levels of government are engaged in permitting in this space, we can assess qualitative differences in the permitting process between the federal and state government. A 2020 Government Accountability Office analysis found that, in 2016, it took the federal government an average of 196 days to approve an application for a permit to drill and by 2019, the average had improved to 94 days. In contrast, Texas takes 23 days to approve properly filed applications and 46 days for improperly filed ones. Incidentally, when it comes to CCUS, the preference is for states to have primary authority for wells; however, with rare exception, the U.S. Environmental Protection Agency (EPA) has permitting authority.
Only three states (Louisiana, North Dakota, and Wyoming) have “primacy” for carbon sequestration (Class VI) wells. As more states develop their own permitting procedures, they can be granted primacy and permit without going through the EPA; even so, the current lack of state authority in permitting Class VI wells presents a major barrier to CCUS development.
Emissions Outlook
Unlike the other resources evaluated in this series, motivation to restrict permitting and siting for oil and gas power plants and pipelines ties heavily to emissions concerns. However, the relationship between natural gas power capacity and emissions is declining—mainly because more natural gas is needed during peak conditions (even if total consumption decreases). To service growing peak needs, pipeline capacity generally must increase, especially if states restrict backup oil. A projection of restricted interstate gas pipeline capacity would only “slightly lower energy-related carbon dioxide” emissions in 2050.
New gas plant development tends to displace legacy generation with higher emissions profiles and provide grid flexibility to balance variable renewables production. A prominent modeling exercise found a 130-gigawatt increase in natural gas generation capacity by 2050 in a 95 percent net decarbonization scenario. In a project-specific permitting context, whether gas infrastructure expansion increases or decreases marginal emissions depends on evolving regional energy conditions.
Conclusion
State permitting laws markedly affect the development of natural gas infrastructure and retention of oil infrastructure in certain states, which may negatively affect power industry costs and reliability in a more acute way than it did several years ago. This is due to new load growth and major restrictions on both alternative generation sources and oil and gas infrastructure—especially in California, New York, and New England. Spillover interstate effects have prompted regional grid operators and federal authorities to scrutinize the reliability effects of these state permitting and siting laws.
Whether lowering permitting barriers to natural gas increases or decreases emissions depends on evolving regional energy market conditions. Such context is often missing from state permitting and siting decision criteria. To improve social welfare, these processes must weigh the economic and reliability benefits of gas expansion and oil retention against their environmental costs. Because gas will play a pronounced role in the power industry for decades to come, reducing permitting and siting barriers to CCS may materially shift the power sector’s emissions profile.
Series: State Energy Infrastructure Permitting and Siting
Meeting electricity demands over the next few decades will require substantial infrastructure expansion throughout the energy sector. This new series surveys the challenges state and local permitting requirements pose to new energy infrastructure.