Register to receive a printed copy(For Lexis Practice Advisor® Subscribers Only)
Lexis Practice Advisor®Free Trial
Learn More AboutLexis Practice Advisor®
This article provides you and your clients with an overview of the federal environmental regulation affecting the oil and gas exploration and production (E&P) industry.
THERE IS SUBSTANTIAL ENVIRONMENTAL REGULATION OF oil and gas E&P at the federal and state levels through the Environmental Protection Agency (EPA) and other agencies. Although it is estimated that states conduct between 80 and 90% of all enforcement actions affecting the E&P industry, these actions are often based on federal environmental regulations.
Environmental regulation is critical to address the environmental impacts of oil and gas E&P, which arise largely because of the methods employed to drill oil and gas wells. As a well is drilled, drill cuttings—rock and mud from the hole—are brought to the surface along with drilling fluids and mud used to lubricate and cool the drill bit, as well as various chemical compounds. Drilling deep and horizontal wells can produce prodigious amounts of this waste, which is generally stored in surface pits or tanks before being disposed of at or near the drilling site (usually by the E&P company).
Environmental regulations ensure that your clients dispose of this waste in an environmentally friendly way, and that complete disposal of waste and rehabilitation of the environment surrounding the well is accomplished by the time drilling is completed. Environmental regulations also require your client, as the owner, to monitor the entire life cycle of an operating well to guarantee the well is properly plugged and abandoned when it has reached the end of its life.
The Resource Conservation and Recovery Act (RCRA) regulates solid and hazardous waste and underground storage tanks. Its intention was to aid state governments in creating their own waste disposal schemes
Exempt and Nonexempt Waste
Drilling waste is exempt from regulation under the RCRA. However, the RCRA does regulate temporary underground hydrocarbon storage tanks located at or near a well site and other waste associated with drilling operations (e.g., empty drums, solvents used to clean drums or trucks, waste associated with painting and sandblasting, and other solvents, chemicals, and acids used at or around drill sites). In total, hundreds of chemical compounds and other items are listed as nonexempt hazardous waste under the RCRA.1
It is important for you to make your client aware that if exempt and nonexempt waste are mixed, this will often cause the entirety of the waste to be deemed nonexempt, which can significantly increase expenses when dealing with large volumes of drilling tailings and mud that may be tainted by only a small amount of nonexempt chemicals or other waste. A listing of exempt waste, and a discussion of specific nonexempt waste under the RCRA follows:
Nonexempt Hazardous Waste
Hazardous waste under the RCRA is categorized into six separate hazard codes: ignitable waste, corrosive waste, reactive waste, toxicity characteristic waste, acute hazardous waste, and toxic waste. Thus, E&P operators must be careful to ensure solvents and other chemicals used at a drill site do not mix with exempt waste from drilling activities.
It should also be noted that the RCRA implements cradle-to-grave requirements for the hazardous wastes it covers. This allows the EPA to establish controls to monitor compliance with the RCRA and clean up procedures required by the RCRA, and the EPA may impose strict recordkeeping and reporting requirements on any party that generates, transports, treats, or disposes of any nonexempt waste.
Although the vast majority of waste at a drill site is exempt from the RCRA requirements, the RCRA remains a powerful tool for the EPA to enforce environmental standards over ancillary activities that occur at or around a drill site.
The Clean Water Act (CWA) is the primary federal law governing water pollution, passed in an effort to protect the environmental integrity of the nation’s waterways. It is administered by the EPA in conjunction and coordination with state governments. The CWA does not cover drinking water, which is covered primarily by the Safe Drinking Water Act (SDWA) ( see section on the SDWA below), but it does strictly regulate what types of waste can be discharged into a waterway—whether that be a wetland, lake, river, estuary, or stream. The CWA also covers the discharge of waste at any shoreline or other land if there is potential for that waste to drain or seep into a waterway or wetland.
Types of Regulated Waste
The CWA regulates two types of waste discharge into waterways: point source and nonpoint source discharge. Point source discharge is a discharge that constitutes a “discernible, confined, and discrete conveyance of pollutants to a water body.” Point source discharge may issue from “any pipe, ditch, channel, tunnel, conduit, well, discrete fissure, container, rolling stock, concentrated animal feeding operation, landfill leachate collection system, vessel or other floating craft from which pollutants are or may be discharged.”
Nonpoint source discharge, on the other hand, generally results from rainwater or other runoff, seepage, or snowmelt moving over and through the ground, which picks up pollutants along the way and eventually deposits those pollutants into lakes, rivers, streams, wetlands, and other waterways. Legally, any water-based pollution that cannot qualify as point source 1. See 40 C.F.R. § 261. pollution is categorized as nonpoint source pollution.
Permitting Process under the CWA
The CWA requires an E&P operator to obtain all appropriate permits and certifications related to point source and nonpoint source waste before the operator can discharge certain drilling-related E&P waste into or near a waterway or wetland. Different permits and certifications are required for different wastes to be discharged. These include certifications from a state environmental body under Section 401 of the CWA, permits from the state environmental agency or the National Pollutant Discharge and Elimination System (NPDES) under Section 402 of the CWA, permits from the NPDES (or its state-run equivalent) under Section 403 of the CWA, and permits from the U.S. Army Corps of Engineers (USACE) under Section 404 of the CWA. Depending on where a well site is located and where waste will be discharged, an E&P operator may be required to obtain as many as four different permits prior to beginning work to drill the well itself.
The permitting process in Texas is somewhat more difficult than in other states, because the Texas Railroad Commission (which regulates all oil and gas activities within the state) is not fully authorized by the EPA to implement an NPDES permit program. Thus, any discharge of E&P waste in Texas that would require permitting under the CWA requires permitting by both the EPA and the Texas Railroad Commission.
The following sections discuss the permit-related sections of the CWA that relate to Texas.
Section 401 of the CWA requires your E&P operator client to obtain a certification that the planned point source discharge contemplated under a Section 404 permit application (to be approved by the USACE) will meet state environmental and water quality standards. A Section 404 permit cannot be issued without this certification. Generally, a Type I certification is issued to your clients under Section 401 if your client’s project:
A Type II certification is issued if your client’s project:
Section 402 regulates your client’s point source discharge of stormwater “associated with industrial activity” through either the NPDES or the relevant state-sponsored equivalent. If your client’s E&P facility discharges or has the potential to discharge stormwater into waters of the United States through construction, clearing, grading, and/or excavation activity, then you need to advise your client that its facility must receive an authorization permit through the NPDES under Section 402. These permits may be individual or general. Individual permits are issued to individual dischargers and are tailored to your client’s facility. General permits are meant to cover several different entities that have the same type of discharge, and they set forth requirements applicable to entire categories of covered discharging entities.
The NPDES permit issued pursuant to Section 402 imposes effluent limits for point source discharge that are tied to the technology available to treat the pollutant prior to discharge, and the resulting water quality when the effluent is released into the body of water.
The EPA bases the limits, which vary by industry, on the performance of the best available technology that is economically achievable for that industry. Your clients are not required to use the technology considered by the EPA in setting the limit but are required to achieve the pollution control levels set by the EPA with that technology.
The EPA standard for water quality is based on the minimum allowable water quality standards set by the relevant state environmental regulatory agency.3
It is worth noting that non-contaminated sediment that is released due to uncontrolled stormwater discharge is exempted from CWA regulation, but if such discharge contains oil or other contamination, you should be aware that your E&P operator client will be liable—even if the discharge was through no fault of its own.
If your client is conducting a construction activity that could release potentially contaminated stormwater into a nonmarine body of water, Section 403 requires compliance with technology and water quality-based treatment standards before a permit is issued to your client. Specifically, the section requires that your client treat the discharged waters to federal minimum standards and also requires discharged waters to meet state water quality standards.
If the construction activity will or could release potentially contaminated stormwaters directly into territorial seas, a contiguous zone, or the ocean, then additional limitations are imposed before an NPDES permit will be issued. In such cases, there may be requirements placed on your client in addition to the technology and water quality standards listed above. These may include:
Section 404 regulates point source discharge of dredging or fill materials into the waters of the United States—including wetlands—through a permit issued by the USACE. A permit will not be issued if it is practicable to dispose of dredging or fill materials in some other way that is less damaging to the environment, or the nation’s waters or water system would be seriously degraded if the proposed disposal activity were to take place.
Before a permit can be issued by the USACE, an operator must obtain a Section 401 state water quality certification from the state entity responsible for enforcement of the CWA, as noted above. Note that although the Section 404 permit is generally issued by the USACE, the EPA retains the right to overrule the USACE’s decision to issue a permit.5
Compliance Monitoring and CWA Jurisdiction
The CWA provides for regular compliance monitoring of waste-generating sites. This is largely accomplished through state agencies, as 46 states have been given authority by the EPA to conduct this monitoring on its behalf, although some states (such as Texas) have only been given partial authority to monitor compliance with the CWA.
In allocating compliance resources, the EPA and the states focus on noncompliance trends and water quality and shift compliance resources based on the amount and type of state and federal resources available. Resources are allocated based on the type of waste discharged, as well as how long it has been since a site has been inspected.
During an inspection, the EPA or its designate will often request to:
If the EPA finds that your client violated the CWA during either a desk audit or a site inspection, it will begin an enforcement action. But, before an enforcement action can commence, the EPA must prove that a spill of oil or a discharge of any other covered waste had a “significant nexus” to “traditional navigable waters.” This is a relatively new restrictive standard that came into play after the U.S. Supreme Court’s decision in the joint Rapanos and Carabell cases, where developers wanted to develop real estate projects on wetlands adjacent to, but independent from, waters that fell within EPA CWA jurisdiction.6 Although the case produced the significant nexus test espoused by Justice Anthony Kennedy in what is viewed as a controlling concurrence, the EPA has issued slightly more aggressive guidance on what water bodies automatically meet this standard. The EPA has stated that the discharge of waste falls within the jurisdiction of the CWA if it is into:
Because of Rapanos, the EPA has also issued guidance on the analysis a field officer must conduct before a significant nexus is found. A significant nexus analysis must assess
The EPA has stated that it can consider certain hydrologic factors when making a significant nexus determination, including:
A nexus is significant if it is simply “more than speculative or insubstantial.” The initial determination of whether a significant nexus exists is made by the relevant EPA or USACE district, and the districts are given broad latitude to implement the CWA according to these EPA guidelines.7
Civil and Criminal Enforcement Mechanisms
The CWA provides a stringent regulatory regime governing your client’s discharge of waste into waters of the United States. The EPA is serious about enforcement of the CWA’s provisions, and has administrative, civil, criminal, and injunctive enforcement powers at its disposal to effect compliance. In the oil and gas industry especially, the EPA’s enforcement of the CWA’s provisions can be extensive.
Civil and Administrative Penalties Available to the EPA
The CWA authorizes the EPA to assess a penalty on any person. The definition of person, in this case, covers individuals, corporations, associations, and responsible corporate officers—certainly almost anyone associated with your clients. The following are the civil and administrative penalties that can be assessed against your clients under the CWA:
A variety of criminal penalties can be levied against your clients for violation of the CWA. They include:
The EPA’s enforcement abilities are vast, and fines can reach billions of dollars. For example, BP was assessed a $5.5 billion civil penalty under the CWA for its part in the 2010 Deepwater Horizon oil spill. This was a negotiated total that was substantially lower than its penalty could have been.8
The SDWA is the premier piece of legislation allowing the EPA— most commonly through state action—to regulate drinking water within the United States. The SDWA seeks to promote healthy drinking water that is free of harmful amounts of pollutants.
The SDWA created the Underground Injection Control (UIC) program, which regulates wastewater disposal and flowback into old/inactive wells or wastewater disposal wells resulting from the drilling process. Essentially, the SDWA regulates all oil and gas wells that involve injection of liquids or gas, either to enhance recovery or to dispose of drilling waste, brine, or water recovered during production. The SDWA does not, however, regulate wells that are solely used for the production of oil and gas without the aid of any ongoing fluid injection to increase pressure.
It is estimated that there are more than 144,000 wells that qualify for regulation under the UIC, with approximately 2 billion gallons of fluid (mostly saltwater brine) being injected each day. The brine is saltier than ocean water, and a relatively small volume of brine from oil and gas production can contaminate a large fresh water aquifer or surface reservoir if the fluid leaks out of the formation it is injected into. Thus, the UIC places great importance on the injection of contaminated liquid into proper sealed formations or salt domes so that it does not escape through faults or fissures into a subterranean aquafer or otherwise find its way to the surface to contaminate drinking water.
Enhanced Recovery Wells
Approximately 80% of UIC-qualifying wells are enhanced recovery wells, where the operator consistently injects brine, water, steam, or other fluid into a producing formation to increase pressure and force oil or gas out of a nearby well with greater efficiency. This process is used in older formations where production without an enhanced recovery process would likely not be commercially viable. Although the method has raised environmental concerns related to drinking water, the process can extend the life of a hydrocarbon field by years, or even decades, and is a method of ensuring that all reserves are gathered from a field before its wells are plugged and abandoned.
The enhanced recovery process is markedly different than hydraulic fracturing or fracking, where fluid and proppants are pumped into a well as it is being completed to create and hold open cracks or fractures in the producing formation so that petroleum and natural gas can more easily flow into the wellbore. Instead, enhanced recovery wells make formerly productive wells commercially productive again. Neither the SDWA nor the UIC provides for regulation of the vast majority of fracking operations (see The SDWA and the Regulation of Fracking below).
Saltwater Disposal Wells
Saltwater disposal wells—which inject saltwater brine that occurs naturally as part of the production process—account for the remaining 20% of wells regulated by the UIC. These wells dispose of the saltwater brine byproduct—estimated at 10 barrels for every barrel of oil produced—at a significantly lower cost than would be required to dispose of the saltwater brine in another manner.
Saltwater disposal wells are often formerly productive oil or natural gas wellbores that have stopped producing paying quantities of petroleum or natural gas but are located within productive oil and gas fields and close to other producing wells. Injection into saltwater disposal wells is limited to the amount of fluid that can be absorbed into the formerly productive geologic formation, and each well is rated separately to account for this volume limitation.
If your client is an operator, it has a fiscal inducement to keep the saltwater brine wastewater that is to be injected into disposal wells as free from hydrocarbons and other contaminants as possible, since any hydrocarbons skimmed off the wastewater is their property—rather than the property of the E&P operator that originally produced those hydrocarbons. Thus, many owners of saltwater disposal wells store the wastewater in a series of settling tanks before pumping it into the disposal wells. Any significant solids, as well as oil and other hydrocarbon products, can be skimmed out of the wastewater in the tanks and resold. This helps ensure that the formation receiving the saltwater brine remains as free from serious contamination as possible and helps keep the disposal wellbore clean and able to operate with less maintenance. And, the process may provide a profit motive for your client as well.
Ideal Underground Strata for the Injection of Saltwater and Other Waste
The SDWA attempts to prevent the underground contamination of drinking water by regulating saltwater injection wells. Requiring an operator to inject brine into a formation that is similar to that from which the brine was extracted makes drinking water contamination from the injection activity less likely. In contrast, if sufficient geologic testing is not conducted and brine is injected into an improper formation with faults that allow for leakage, aquifer, and/or groundwater, contamination is quite possible. Thus, the SDWA requires an operator to only inject fluid into strata that is porous and permeable enough to accept the volume of fluid proposed, and which can contain and confine the fluid solely within that formation. If strata is faulted or fractured, it is not acceptable for injection well purposes. Similarly, if strata contains hydrocarbons—even if they are not capable of being produced or are largely depleted—the strata may not qualify, because injection of wastewater may be challenging for the operator. The ideal formation for your client to use for injection purposes is either a porous dry layer of strata, or a porous layer of strata already partially or fully populated with saltwater.
To identify the ideal layer of strata in an area, your client should hire geologists to evaluate core samples and/or records of core samples from when the well was drilled. If quality geologic information is not available, information gathered from geophysical mapping may be used to determine the proper formation for disposal purposes. Depending on where the ideal strata is located, the wellbore may have to be manipulated to ensure that wastewater only travels into the appropriate formation and does not seep into formations above or below.
The Permitting Process for Disposal and Injection Wells in Texas
Operators of saltwater disposal and enhanced recovery injection wells must obtain a permit. Because the SDWA is largely administered by the states, this is generally done through the state body that regulates the oil and gas industry within that state.
Before a permit is issued, the state authority evaluates the application to determine if:
In evaluating whether the creation and operation of a well is in the public interest, state regulators evaluate “whether the well will provide needed additional disposal capacity and an economical and safe means of disposing of oil and gas waste, thereby increasing the ultimate recovery of oil and gas and preventing waste.” However, in the seminal case of Railroad Commission of Texas v. Texas Citizens for Safe and Clean Water, the Texas Supreme Court ruled that the state regulatory agency could not take into account other factors such as increased truck traffic, perceived public safety threats, general community impact, or diminution of local property values when determining whether to grant a saltwater disposal well permit.9 Additionally, notice must be given to the surface owners, other nearby operators, and local government officials, and the operator must review records for all abandoned wells within a defined radius to ensure there can be no fluid migration into an improperly abandoned well (thereby creating liability for your client as operator of the injection well).
After these standards are met, the state regulatory authority will review the construction plan for the well to ensure that its design will protect drinking water. Depending on various state regulations, a saltwater disposal well must generally be constructed with three or four layers of cement and steel casing before it is approved for operation. While different states vary their regulations slightly, best practices for both steel casing and cementing activities have been promulgated by the American Petroleum Institute, and these practices are generally followed by all hydrocarbon-producing states.10
The Casing and Cementing Process
The first casing—the surface casing—is the widest and is placed downhole, with a concrete encasement that seals the area from the surface to the bottom of the deepest discovered groundwater aquifer. In most cases, a production casing, with full concrete cladding, comes next that travels from the surface to the very bottom of the wellbore. In some cases, an intermediate casing, with concrete encasement, is placed between the surface casing and the production casing, creating an extra layer of protection for the groundwater aquifers the well passes through. Finally, a steel tubing string and packer are lowered into the wellbore. The tubing string has perforations at its bottom, which will allow the saltwater injected to drain into the appropriate formation. The packer is a mechanically or hydraulically set seal that is placed between the tubing string and the production casing—generally at least 50–100 feet above the highest perforation level of the tubing string. The space between the production casing and the tubing string is often filled with hydraulic fluid before the packer is fully set, thus helping counteract downhole pressure on the bottom of the packer, alerting the operator if the packer begins to leak and saltwater begins to travel up-hole between the production casing and the tubing string. This hydraulic fluid also helps prevent corrosion from attacking the production casing and the outside of the tubing string.
If both statutory and mechanical requirements are met, the state regulatory authority will issue your operator client a permit for the construction of its saltwater disposal well. However, before the well becomes operational, your client must demonstrate that the well can meet a very strenuous pressure test designed to model the harshest conditions the well might encounter during its lifecycle. If the well passes this pressure test, it may become operational. If it does not, it must either be capped and abandoned, or must be recompleted or repaired. The EPA only requires that this strenuous pressure test be repeated every five years. However, each state differs in this requirement, with some requiring your operator clients to conduct and report an annual pressure test on all saltwater disposal wells within the state. Monthly logs must also be kept of average operating pressure, to ensure the packer or the casing is not slowly failing between pressure tests.
To determine operating volume for the well, many state regulatory agencies will require your clients to perform a step test, in which different and increasing volumes of fluid are pumped down the wellbore while bottom pressure is monitored. Maximum volume/pressure for the well is generally set just below the point at which the fluid injected during the test causes the formation to begin to break down. Pursuant to EPA guidelines, this test must be witnessed personally by state regulatory personnel.
The permitting process is not a static process. To maintain an active permit to operate a saltwater disposal well, your operator client must prove that it regularly monitors the well and must keep significant records of disposal volumes and pressures. Your client must also monitor and report regularly on water quality in the area surrounding the well.
Transportation of Saltwater to an Injection Well Site
The vast majority of saltwater brine is stored temporarily at a well site until a sufficient quantity has been produced to be transported via truck to a disposal well. The cost to transport saltwater brine is generally calculated on a per-barrel-perhour basis, with the national average being $1.00 per barrel per hour of transportation time. However, disposal wells are few and far between in oil and gas producing states like Pennsylvania and New York but are plentiful in Texas. The cost of disposing of a barrel of brine on the East Coast may be between $4.00 and $6.00, whereas the cost may be as little as $0.50 per barrel in the Barnett Shale in North Texas. Thus, the location of a saltwater disposal well may greatly affect the economics of a productive formation your clients own a part of.
Due to the cost of transportation and, in some cases, the rarity of saltwater disposal wells, some E&P companies have begun to develop systems to filter and reuse produced brine as semifresh water for other drilling activities. These efforts are in their infancy and are still relatively uneconomical except in areas where few injection wells are present, but they do present your clients with interesting alternatives to the traditional saltwater injection option.
The SDWA and the Regulation of Fracking
Since 2005, the SDWA has specifically excluded regulating the underground injection of most hydraulic fracturing operations. Some believe this is because all such fluid eventually works its way out of a well (and therefore does not remain permanently in the ground). Others see it as a specific exclusion brought about by aggressive industry lobbying. Regardless of the cause, most fracking operations remain outside the jurisdiction of the SDWA.
The exception to this rule is that the SDWA does still regulate the injection of diesel fuel as a tool used in fracking, because diesel often contains impurities such as benzene, toluene, ethylbenzene, and zylene that are highly mobile in groundwater and pose a risk to human health. Although diesel is not often used in fracking operations, it can be used as a large or small component of fracking fluid to adjust viscosity and fluidity, or as a solvent for the fractures themselves. If your client wishes to conduct a fracking operation using diesel fuel as a primary base (or carrier) fluid, as a component of its fracking fluid, or as a solvent, then it must seek an additional permit to do so from the EPA. The EPA is given significant discretion when deciding whether to grant such a permit.11
The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) is a significant piece of environmental regulation meant to clean up sites contaminated with toxic chemicals. CERCLA creates strict joint and several liability for all present and past property owners and designates Superfund sites.
CERCLA contains two exclusions affecting the oil and gas industry: the E&P waste exclusion and the petroleum exclusion. The petroleum exclusion is relatively clear cut. If petroleum is spilled, CERCLA liability will not attach, because that spill is regulated under other federal laws, including the SDWA and the CWA.
The E&P waste exclusion is a different matter. Many believe this exclusion was originally meant to fully exclude all drilling-related E&P waste from CERCLA regulation. But early case law on the subject failed to fully recognize that exclusion, if it was indeed the intent.
The EPA has utilized CERCLA to investigate drilling and injection well sites, alleging that E&P waste (such as drilling mud, tailings, injectable fluids, and brine) may be the cause of ground or water contamination. However, this is rare, as the EPA has to find elevated amounts of hazardous substances (e.g., toluene, benzene, zylene, and other hazardous chemical compounds that are associated with either commercial-grade solvents or the use of substantial amounts of diesel fuel during the fracking process) in E&P waste before liability may attach.
CERCLA has recently been used by the EPA to investigate fracking methods in Pennsylvania, Wyoming, and other states. However, no enforcement actions have been taken as a result of these preliminary investigations. In reality, other environmental regulations such as the CWA and the SDWA are more easily tailored to oil and gas regulation and are therefore more often used by the EPA as enforcement tools for fracking operations and within the larger E&P industry.
The Clean Air Act (CAA) regulates major source and minor source entities that emit any of 188 separate air pollutants and is the preeminent federal law regulating toxic pollutants released into the air.
Major source polluters are individual entities that either have the potential to emit at least 10 tons of a single toxic air pollutant per year or have the potential to emit 25 tons of two or more air pollutants during any given year. Major source polluters (such as power plants) are individually regulated and must install emission control devices that drastically reduce the amount of pollutants released into the atmosphere. The standard for these control devices is deemed to be the maximum achievable control technology; each major source facility must install the state-of-the-art air-scrubbing technology to minimize air pollution. Essentially, whatever is the best technology available in the marketplace.
Minor source polluters emit less than the major source limits on a per-installation basis. These polluters are not required to install emission control devices unless an aggregated number of minor source polluters would, together, produce enough toxic air pollution to qualify as an aggregated major source polluter.
As with many of the federal regulations discussed above, enforcement of the CAA is left first to the states, with oversight from the EPA.
Aggregation and the Historic Oil and Gas Industry
Historically, EPA regulations exempted individual oil and gas wells from being aggregated together for purposes of the CAA, unless they were located within a municipal area with one million inhabitants or more. Thus, the vast majority of the upstream oil and gas industry was historically exempt from CAA standards. This is because individual oil and gas wells do not produce sufficient air pollutants to qualify as a major pollution source under the CAA and were too diverse in location and scope to be aggregated together into a single major source polluter. However, the situation began to change in the mid-2000s.
The Trend toward Aggregation
By the mid-2000s, the nation’s oil and gas industry was expanding rapidly. With the discovery of multiple shale gas fields throughout the country, many near or directly under populated residential areas, there was heightened concern about environmental standards for the oil and gas industry under the CAA. There was particular focus on natural gas wells, which are a major source of methane emissions.
In 2007, the Acting Assistant Administrator of the EPA published a memo that stated interconnected oil and gas facilities could be aggregated for the purpose of determining whether they were major source polluters under the CAA if they:
This rule has been adopted by most state agencies tasked with enforcing the CAA. The EPA concluded that aggregation would not be appropriate in a great majority of cases, but the proximity standard allowed for further regulation of the oil and gas industry under the CAA.12
The Modern Push to Aggregate
In 2009, the Assistant Administrator for the EPA withdrew the above-mentioned memo and published her own guidelines for determining whether aggregation was appropriate within the oil and gas industry. The McCarthy Memo, as it later became known, took the EPA back to a “case-by-case analysis” for aggregation determinations, with the hope that aggregation could be found for oil and gas facilities that were significantly farther apart than the quarter mile provided for under the previous memo.
Not all state environmental regulatory agencies automatically followed the EPA’s lead on this front. As late as 2012, many state agencies were still operating under the quarter-mile guidance. The EPA eventually forcibly reminded each state that this was no longer the standard.
Litigation Shows Limits on Aggregation
In MacClarence v. EPA, the U.S. Court of Appeals for the Ninth Circuit upheld a ruling against a private citizen who attempted to force the EPA to aggregate all of BP’s wellheads located in Prudhoe Bay, Alaska, even though that field was spread over more than 300 square miles.13 In its denial of the application for aggregation, it was stated that the request “stretches the concept of proximity” that otherwise defines aggregation determinations within the CAA concept.
In Summit Petroleum Corp. v. EPA, the EPA decided to take an aggressive stance on aggregation that was ultimately struck down by the U.S. Court of Appeals for the Sixth Circuit.14 In Summit, which began with a 2005 application for an aggregation determination, the EPA initially relied on its early guidance on aggregation to determine that the natural gas wells and a processing facility—which were roughly eight miles from end to end and covered an area of 43 square miles—could not be aggregated. However, a final determination was not made by the EPA until two weeks before the McCarthy Memo was issued. At that point, the final EPA determination stated that the Summit facility should be aggregated under the CAA. Summit appealed, and the Sixth Circuit ultimately disagreed with the EPA. The court remanded the case back to the EPA to make a revised determination based on “the proper, plain-meaning application of the requirement that Summit’s activities be aggregated only if they are located on physically contiguous or adjacent properties.”
In response to Summit, the EPA instructed its various field regions (outside of the Sixth Circuit) to continue to apply the pre-Summit concept of “adjacent” when making an aggregation determination under the CAA, leaving the field offices located within the Sixth Circuit alone to abide by Summit. The U.S. Court of Appeals for the D.C. Circuit patently rejected this approach in Nat’l Envtl. Dev. Ass’ns Clean Air Project v. EPA,15 citing the need for a uniform national standard for CAA aggregation policy.
New Rules to Change Aggregation Standard
While the CAA standards currently in existence still adhere to the McCarthy Memo’s aggregation guidelines, the EPA has proposed new rules on aggregation, to clarify regulation of the oil and gas industry under the CAA. These rules propose to bring back the quarter-mile proximity standard, but also propose new stringent standards on methane gas and volatile organic compound emissions. Thus, the oil and gas industry may receive some relief in the proximity standard, but the level of environmental discharge that constitutes an entity being deemed a major polluter may decrease significantly if aggregation is found.
Ultimately, the trend over the past several years has been toward greater regulation of the oil and gas industry under the CAA. Whether this trend continues may be closely tied to the political process. For now, your oil and gas company clients should make plans with more stringent environmental regulations under the CAA in mind.
The Oil Pollution Act (OPA) was passed by Congress largely in response to the Exxon Valdez oil spill in Prince William Sound, Alaska. It imposes liability on responsible parties for discharge of oil into or upon the navigable waters or shorelines of the United States, or within the “exclusive economic zone” of the United States (which extends up to 200 miles offshore). The OPA requires an E&P company to implement a plan to prevent oil spills, as well as a detailed containment and cleanup plan should an oil spill occur. It also contains certain education requirements and limits the ability of certain vessels that have spilled large amounts of oil from traveling to Prince William Sound, Alaska.
The OPA creates a strict liability standard for any party responsible for oil spills, meaning that the spill alone—rather than any showing of negligence or gross negligence—is enough to incur liability. It also channels liability to certain entities involved in the E&P process. For instance, in offshore E&P activities, the holder of the drilling permit is legally responsible under the OPA for any oil spill, even if another party contributed to causing that spill. A party that is strictly liable under the OPA may bring a contribution action against a party that is not strictly liable under the OPA, but any such litigation is irrelevant for the purposes of government enforcement of the OPA.
The OPA has a two-tiered liability structure. It first assesses unlimited costs to remove the discharged oil or to “prevent, minimize, or mitigate oil pollution from such an incident.” This is known as the removal cost contingent of the OPA’s regulation scheme. Second, the OPA imposes a monetary penalty for damages resulting from the discharge. For offshore oil spills, this penalty is capped at $134 million per incident. However, the damage cap is lifted if there is a showing of gross negligence or willful misconduct, or if the spill was proximately caused by the responsible party or its employee, agent, or contractor violating a federal safety, construction, or operating regulation.
The OPA also specifically disclaims preemption of state environmental laws. So, even if an E&P producer is liable under the OPA for removal costs and damages, it may also be separately sued in state court for additional damages that would normally be preempted. Federal criminal statutes are also unaffected by the OPA and its damage caps. For major oil spills, criminal restitution can often be significantly higher than the OPA damage caps, even though these penalty amounts will not be shared with private individuals and entities damaged by the spill.
The OPA instituted a permanent $1 billion trust (from a tax on oil sales) that is available to fund the cleanup of oil spills on navigable waterways throughout the United States if the responsible party is unwilling or unable to pay to do so.
The Toxic Substances Control Act (TSCA) of 1976 allows the EPA to regulate chemicals that pose an “unreasonable risk to health or to the environment,” as well as to regulate new entrants into the chemical marketplace. The TSCA has not traditionally been used to regulate the oil and gas industry. However, the EPA issued an Advance Notice of Proposed Rulemaking on May 9, 2014, that sought public comment on:
The types of chemical information that could be reported and disclosed under [the] TSCA, and the approaches to obtain this information on chemicals and mixtures used in hydraulic fracturing activities, including non-regulatory approaches.
This is clearly an evolving area, but the EPA’s efforts indicate a desire to begin the collection of information about the composition and potential health and environmental effects of various chemicals used in the fracking process. This in turn indicates that the EPA may increase regulation in the future. It is reasonable to believe that regulation of the oil and gas industry under the TSCA may be coming in the not-sodistant future.
The Endangered Species Act (ESA) of 1973 provides for the federal conservation of threatened or endangered species throughout their range and also works to protect the habitat and ecosystem on which they depend. The ESA prohibits any person from taking any endangered or threatened species. The term take includes harassing, harming, pursuing, shooting, wounding, killing, capturing, or collecting any listed species and also includes attempting to engage in any such conduct with a listed species.
The ESA has a significant impact on oil and gas exploration, as a drill site may require the clearing and/or the complete disruption of upwards of five acres of previously undisturbed land, and seismic operations may disturb species on land and underwater. Before any action that may disturb an endangered or threatened species occurs, an operator must determine whether the property is populated by a threatened or endangered species and ensure that it does not inadvertently take an endangered or listed species without government approval.
Section 10 of the ESA requires any private party undertaking an activity that may result in a take of a protected species to obtain an incidental take permit prior to beginning the threatening activity. As part of the permitting process, the applicant will be required to develop a habitat conservation plan that details the steps it will take to offset any harmful effects its proposed activity will have on the protected species. These conservation plans may include such proposals as:
Even if your operator client is issued an incidental take permit, it must be very careful. When exploring in an area populated by endangered or threatened species, it is wise for you to advise that your client build such information into the standard lease form, so that it is protected if it cannot drill due to ESA concerns.
As the government is in the process of potentially adding another 251 species to the 1,300+ endangered species list, the ESA will likely become more restrictive to the oil and gas industry. With potential civil and criminal penalties for even small infractions, your E&P operator clients must stay ahead of the curve in this area of regulatory concern.
The federal government does not merely seek civil penalties against your E&P operator clients for violation of environmental laws. It also seeks to assess criminal penalties against them, should their activities cause an environmental impact. Some of the more popular criminal statutes that have been utilized against the oil and gas industry are the Migratory Bird Treaty Act (MBTA) and the National Marine Sanctuaries Act (NMSA).
The MBTA was originally passed in 1918 to protect birds migrating between the United States and Canada. The MBTA makes it unlawful to hunt, kill, capture, or sell birds protected by the act. This act has famously been used to restrict the sale of bald eagle feathers, eggs, and nests. Following the Exxon Valdez disaster, the U.S. government chose to pursue criminal penalties against Exxon under the MBTA, arguing that the spill caused the death of a significant number of protected migratory birds.
The government has traditionally stated that any take of a protected migratory bird would result in strict liability and a significant volume of case law has previously agreed. However, certain recent cases have held the opposite. For example, a federal court in North Dakota refused to impose liability on an E&P operator whose open (and lawful) oil reserve pits caused the incidental death of migratory birds. What was once a clearly defined body of law now may be in flux. However, the safest approach for your E&P operator clients is to operate with the same caution as was required in the past. No company or client wants to be the newest test case under the MBTA.
The NMSA authorizes the Secretary of Commerce to designate certain areas of the marine environment as national marine sanctuaries if they have special national significance due to their conservation, recreational, ecological, historical, scientific, cultural, archaeological, educational, or aesthetic qualities. Once an area is designated as a sanctuary, the NMSA provides for unlimited liability for any damages occurring to such a designated area, plus a civil penalty of up to $130,000 per day per violation. In the case of an offshore oil spill, these damages could be significant for your clients, as large areas (such as the entirety of the Florida Keys) are designated as national marine sanctuaries. Largely because there are no damage caps available, the government has threatened or pursued criminal liability against E&P operators under the NMSA in several notable instances, including after the Deepwater Horizon oil spill. This is an area you should certainly monitor on behalf of your clients.
To find this article in Lexis Practice Advisor, follow this research path:
RESEARCH PATH: Energy & Utilities > Energy & Environmental Regulation > Environmental Regulations > Practice Notes
For more information about the National Environmental Policy Act, see
> 5 ENERGY LAW AND TRANSACTIONS § 120.02
RESEARCH PATH: Energy & Utilities > Energy & Environmental Regulation > Environmental Regulations > Secondary Materials
For a discussion of the use of water in oil and gas operations, see
> WATER USE IN OIL AND GAS OPERATIONS
For an overview on the reclamation of waste material, see
> RECLAIMING TANK BOTTOMS, HYDROCARBON WASTE, AND OTHER WASTE MATERIALS