In the USA, mineral rights are predominantly owned by private citizens or companies, rather than the state or federal government.

Private mineral ownership is based on the principle that the owner of real property owns everything both above and below the surface, including the minerals. US common law has modified this principle to address the existing nature of hydrocarbons within the reservoir.

Severance

It is common in hydrocarbon-producing states for the mineral rights to be severed from the surface rights to the land. Severance often occurs when a property owner sells the surface but retains rights to the minerals or to the subsurface. In turn, the mineral rights can be separated into undivided shares, or the “minerals” can be divided into rights for the oil and natural gas, water and/or other named minerals or resources (eg, sulphur, helium, etc).

In areas with significant historical production, there may be dozens of mineral owners with rights underlying a single tract, with the surface owner having no right to the produced minerals. These circumstances can generate complex title issues that must be understood by mineral interest owners and exploration and production companies leasing and drilling such interests.

The Lease

The oil and gas “lease” is more of a hybrid of a deed and contract than a traditional real estate lease. The lease typically conveys oil, gas and certain mineral rights in the leasehold lands to the lessee, who accepts those rights in exchange for payment to the lessor of a share of production (or the proceeds therefrom).

The majority of modern oil and gas leases grant the lessee the right – but not the obligation – to develop the minerals during the initial term of the lease. The nature of the property interests conveyed by the lease varies from state to state, and may be further defined according to the terms of individual leases.

Hydrocarbon Ownership

Typically, states follow one of two theories of hydrocarbon ownership: ownership-in-place or the exclusive right-to-take. Under the ownership-in-place theory adopted by courts in many hydrocarbon-producing states (including Texas), the landowner or mineral owner owns a real property interest in all substances lying within the owned land, including oil and gas.

The rule of capture

The landowner’s ownership interest is qualified, in the case of oil and gas, by the operation of the rule of capture, whereby the owner of a tract of land acquires title to the oil and gas produced from wells drilled on this land, even if the oil and gas migrated from neighbouring tracts. Thus, subject to trespass, the ownership of the substances is lost if the oil and gas underlying a tract of land migrates from beneath that tract.

However, the rule of capture is not an absolute rule and has been altered in many hydrocarbon-producing states to promote more ordered production. For example, gas that has already been extracted from the land and injected into underground storage is no longer subject to the rule of capture and remains the property of the person who originally captured the gas.

Many states have also adopted the doctrine of correlative rights. This doctrine limits the rule of capture when the extraction or removal of hydrocarbons is completed negligently or in a manner that causes waste. In that case, the mineral owner may be entitled to recover damages from the operator that negligently or wastefully extracted the hydrocarbons.

The exclusive right-to-take theory of ownership

Other states, such as Oklahoma, follow the exclusive right-to-take theory of ownership, under which the landowner does not own hydrocarbons beneath the owned land and, instead, merely has the exclusive right to capture the substances by conducting operations on the land. Once reduced to dominion and control, the substances become the object of absolute ownership but, until capture, the property right is described as an exclusive right to capture.

Effects of theories of ownership

The two theories of ownership have wide-ranging effects on the oil and gas industry, which have been examined by a host of professionals during the last severe waves of energy restructurings. In states that follow the ownership-in-place theory, a lessee’s interest in an oil and gas lease is viewed as a fee-simple determinable estate in the oil and gas in place. In states that follow the exclusive right-to-take theory, courts typically characterise the lessee’s interest as an irrevocable licence or a profit à prendre.

In the USA, an oil and gas lessee has an implied right to make reasonable use of the surface to develop and produce oil and gas from the land. This is particularly important given the frequency with which the mineral estate is severed from the surface estate. By classifying the mineral estate as the “dominant estate”, the lessee is assured that a surface estate owner cannot prevent reasonable development activities, thereby rendering the mineral estate worthless. Nevertheless, conflicts between surface owners and mineral owners or lessees are frequent, and many lessees and surface owners execute surface use agreements in advance of significant development of the mineral estate, or provide for specified restrictions within the lease itself.

Federal, tribal and state government land

While private mineral ownership dominates in the majority of hydrocarbon-producing US states, the federal, tribal and most state governments own property which they may then lease for oil and gas development. The federal government owns about 30% of all onshore lands located in the USA and has extensive regulations governing the leasing of federal lands, including the payment of royalties, etc. In order to obtain a federal lease, companies execute a lease with the Bureau of Land Management (BLM) requiring the payment of a royalty to the government. Tribal regulation varies considerably across tribes, and the tribes have varying degrees of technical capacity with respect to oil and gas development, which is partly the justification for the Bureau of Indian Affairs to have concurrent jurisdiction over certain tribal issues.

This structure of dual regulation can cause extended delays in obtaining approval to assign tribal leases and/or obtain drilling permits on tribal lands. Thus, operations on tribal land can be complex, and tribal land ownership adds regulatory hurdles to a company’s oil and gas operations. 

Domestic onshore oil and gas development is regulated primarily by the applicable state where oil and gas operations occur, but a variety of state, federal and tribal government agencies govern petroleum development activities in the USA.

While historically the US federal government has left regulatory oversight of onshore oil and gas exploration and production activities to state governments, public concern and media scrutiny about oil and gas operations have increased as hydrocarbon development continues to expand into more urban areas. In response, regulators and legislators at both the federal and state levels have taken steps to increase regulations and enhance enforcement against oil and gas operators in order to protect public safety and natural resources. 

At the state level, numerous agencies have the express oversight of oil and gas development within their states (although, of note, the level of hydrocarbon production within the states varies considerably). At the federal level, the following agencies have primary responsibility for governing oil and gas operations: 

• the US Environmental Protection Agency (EPA) enforces many of the federal environmental statutes and regulations in the USA, including many affecting oil and gas development;
• the BLM manages onshore oil and gas operations conducted on federal lands;
• the Bureau of Safety and Environmental Enforcement (BSEE) works to promote safety, protect the environment and conserve offshore resources – it also grants and manages rights-of-way for oil and gas pipelines on the outer continental shelf (OCS);
• the Bureau of Ocean Energy Management (BOEM) manages the exploration and development of offshore resources;
• the Federal Energy Regulatory Commission (FERC) regulates the rates, terms and conditions of interstate natural gas and oil/liquids transmission under the Natural Gas Act (NGA), and the Interstate Commerce Act (ICA) is responsible for reviewing proposals to build and operate liquefied natural gas (LNG) terminals and interstate natural gas pipelines;
• the National Oceanic and Atmospheric Administration provides foundational information and services to support renewable and conventional energy siting and operations; 
• the Pipeline and Hazardous Materials Safety Administration (PHMSA) seeks to protect people and the environment from the risks inherent in the transportation of hazardous materials, exercising jurisdiction over certain onshore gathering pipelines and produced water pipelines (eg, those used in conjunction with saltwater disposal wells);
• the Bureau of Indian Affairs regulates oil development on tribal lands;
• the Office of Natural Resources Revenue is responsible for collecting royalties owed to the federal government from oil and gas production;
• the US Fish & Wildlife Service works to conserve, protect and enhance fish, wildlife and plants and their habitats, and exercises jurisdiction over endangered and threatened species (and their habitats) under the Endangered Species Act;
• the US Department of Homeland Security may exercise jurisdiction over facilities storing certain chemicals of interest that could present security issues;
• the US Occupational Safety and Health Administration enforces workplace safety and health legislation;
• the US Army Corps of Engineers has permitting authority over work conducted in navigable waters of the USA and discharges of dredge or fill material in waters of the USA, including wetlands;
• the US Maritime Administration (“MARAD”) regulates numerous areas relevant to marine oil and gas activity, including ships and shipping, shipbuilding, port operations, vessel operations, national security, environment and safety, and is the lead agency in reviewing applications for licences to construct and operate oil and natural gas in deepwater ports;
• the US Coast Guard works in tandem with MARAD to review licence applications for oil and natural gas deepwater ports, and is responsible for overseeing the design, construction and activation phases, environmental monitoring programmes, operational procedures, risk assessments, security plans, and safety and inspections for oil and gas projects – the Coast Guard also works with the US EPA, other federal agencies, state and local governments, the responsible parties, and oil-spill response organisations to respond to oil spills at sea;
• the US Department of Energy (DOE) oversees maintenance of the USA’s emergency petroleum reserves and reviews applications to import and export natural gas and LNG; and
• the US Department of State reviews permit applications for the construction, connection, operation and maintenance of oil and natural gas pipelines that cross the international boundaries of the USA. 

At both state and federal levels, recent regulatory initiatives have primarily focused on six key issues related to shale hydrocarbon development:

• disclosure requirements for the chemicals used in hydraulic fracturing (ie, “fracking”) fluids;
• the management and disposal of water used in, and the waste fluids generated by, drilling operations;
• regulation and oversight relating to the location and operation of underground injection control wells to minimise and mitigate potential increases in seismicity;
• casing, cementing and other well-construction standards and assuring the physical integrity of the well;
• the extent of emissions of methane and other greenhouse gases (GHGs) from equipment and operations; and
• the extent of public lands and waters available for development.

At the state level, a number of the traditional hydrocarbon-producing states have revised existing regulations to include heightened well-drilling and installation standards, waste fluid management requirements and varying disclosure requirements. 

In general, the regulation of oil and gas operations at the local government level is limited, with most states having laws that pre-empt municipal, county, borough, or parish governments from regulating oil and gas drilling (except with respect to certain zoning laws). One notable exception is Colorado, which, in 2019, placed regulation of the surface impacts of oil and gas exploration in the control of local communities, as co-equals with the state.

There is no national oil or gas company in the USA.

A number of laws and regulations affect the oil and gas industry throughout the production cycle (ie, from upstream exploration and production, through to midstream and downstream transportation, processing and refining). As described in 1.2 Regulatory Bodies, the system of laws and regulations affecting oil and gas operations varies depending on the state where operations are conducted and/or whether operations are conducted on privately owned or government-owned property. What follows is a high-level review of major US laws and regulations affecting the upstream industry.

Onshore LNG

Mineral Leasing Acts of 1920 and 1947

The development of oil and gas on federal properties starts with leasing programmes that are governed primarily by the Mineral Leasing Acts of 1920 and 1947. The Mineral Leasing Act of 1920 opened federal lands to hydrocarbon development and initially offered the oil and gas operator/lessee an exclusive two-year prospecting permit covering 2,560 acres of unproved land. The lessee was required to begin drilling operations within six months, and to drill wells to an aggregate depth of 2,000 feet within two years. Upon the discovery of oil or gas in paying quantities, the lessee was entitled to a 20-year lease of one-quarter of the land, at a royalty of 5% and an annual rental of USD1 per acre. 

Because of concerns about physical and economic waste under a system of unfettered rule of capture, legislators passed amendments to the Mineral Leasing Act, culminating in the Mineral Leasing Act of 1947. One such important amendment was enacted in 1935 when the principle of compulsory unitisation was granted to the Department of the Interior, to cause lessees to enter into a co-operative unit plan of production to lease and develop a specified federal area. Similar to forced pooling (whereby an operator is permitted to “pool” with other mineral interest and working interest owners to produce a unit), compulsory unitisation allows the federal government to force interest owners to effectuate a common unit development plan.

Congress also amended the terms of federal leases in 1946 to encourage additional exploration and development by providing for a flat 12.5% royalty on non-competitive leases and reducing the term of competitive leases from ten to five years. In April 2022, the US Department of the Interior increased the royalty rate on new onshore leases on federal lands to 18.75%. Finally, the Mineral Leasing Act of 1947 added an additional 150 million acres of federal lands to the public domain, and generally affirmed the amendments to the Mineral Leasing Act of 1920, other than providing that all proceeds generated from federal hydrocarbon development be directed to the federal treasury, rather than state treasuries.

Natural Gas Act and Natural Gas Policy Act of 1978

Congress also enacted legislation governing midstream activities, including natural gas and oil pipeline transportation. The NGA gives FERC regulatory authority over various aspects of natural gas transportation. Specifically, FERC has jurisdiction over the siting, construction and operation of onshore LNG import and export facilities, pursuant to NGA Section 3, and interstate natural gas pipelines (including interstate storage facilities), pursuant to NGA Section 7. Such facilities may not be constructed or operated without a FERC-issued certificate of public convenience and necessity.

FERC jurisdiction

Furthermore, Sections 4 and 5 of the NGA give FERC jurisdiction over the rates, terms and conditions of service on interstate natural gas pipelines and storage facilities, which authority does not, however, extend to LNG import and export facilities. Under the ICA, FERC has similar authority over the rates, terms and conditions of service on interstate oil and liquids pipelines. However, unlike interstate natural gas pipelines and onshore LNG import and export facilities, FERC has no jurisdiction over the siting, construction and operation of interstate oil and liquids pipelines.

FERC has broad enforcement authority under the NGA and the Natural Gas Policy Act of 1978, including the ability to levy civil penalties for rule violations or market manipulation of up to approximately USD1.496 million per violation per day, subject to annual adjustment for inflation. FERC’s civil penalty authority under the ICA allows for civil penalties of up to USD15,662 per violation per day for failure to comply with FERC orders, and up to USD1,566 per violation per day for most other violations (all of which are subject to annual adjustment for inflation).

Pipeline and Hazardous Materials Safety Administration

The safety of interstate natural gas pipelines, oil pipelines and LNG facilities falls under PHMSA’s jurisdiction. PHMSA’s primary mission is to regulate the transportation of hazardous materials and to protect people and the environment from the risks inherent in the transportation of hazardous materials by pipelines and other modes. PHMSA has developed regulations and standards for the handling and safe transport of hazardous materials in the USA, and to ensure safety in the design, construction, operation, maintenance and spill response planning of approximately 2.6 million miles of natural gas and hazardous liquid transportation pipelines. In November 2021, PHMSA issued a rule that expanded reporting and safety requirements to apply to approximately 425,000 miles of previously unregulated onshore gas gathering pipelines.

PHMSA’s inspection and enforcement staff promulgates the agency’s safety and training standards and ensures that the entities under its jurisdiction comply with the pipeline and hazardous materials safety regulations. PHMSA’s jurisdiction extends beyond pipelines transporting hazardous materials, to include entities that manufacture, re-qualify, rebuild, repair, recondition or retest packaging (other than cargo tanks and tank cars) used to transport hazardous materials.

PHMSA has a full range of enforcement tools to ensure that the hazardous material transportation industry takes appropriate and timely corrective actions for violations, responds appropriately to incidents, and takes preventative measures to preclude future failures or non-compliant operation. Violations of PHMSA’s regulations can lead to both civil and criminal enforcement proceedings in addition to fines ranging from USD582 (for training violations) up to USD257,142 per day per violation (for pipeline safety violations) and USD2,576,627 for a related series of violations.

Offshore LNG

Department of Energy’s Office of Fossil Energy approval

Natural gas deepwater ports – but not oil deepwater ports – must secure approval from the Department of Energy’s Office of Fossil Energy and Carbon Management (“DOE/FECM”), for the import and/or export of natural gas, and from FERC, for associated natural gas pipeline facilities onshore, in state waters, and landward of the deepwater port’s high-water mark. Thus, unlike the application process for onshore LNG facilities, the application process for offshore LNG facilities is governed by both the NGA and the Deepwater Port Act of 1974.

Federal Oil and Gas Development

National Environmental Policy Act

Federal oil and gas development is also subject to the National Environmental Policy Act (NEPA), which was one of the first laws to establish a broad national framework for protecting the environment. The basic policy underlying NEPA is to ensure that all branches of government give proper consideration to environmental impact, prior to undertaking any major federal action that has the potential to significantly affect the environment.

NEPA requires each federal agency to prepare an environmental impact statement (EIS) before taking any federal action that could significantly affect the quality of the human environment, subject to certain exclusions and exemptions. When preparing the EIS, the agency is required to evaluate reasonable alternatives that are technically and economically feasible and meet the purpose and need of the proposed action and the direct, indirect and cumulative environmental impacts of both the proposed action and any such alternatives. The requirements of NEPA may result in increased costs, delays and the imposition of restrictions or obligations on an oil and gas company’s activities, including restricting or prohibiting drilling.

Offshore operations are governed by an additional set of complex regulations reflecting the ecological sensitivity of the shorelines and shallow-water areas of the US Gulf of Mexico (GOM), as well as the additional technical complexity of offshore production.

US Oil Pollution Act of 1990

The US Oil Pollution Act of 1990 (OPA) and related regulations impose a variety of requirements on “responsible parties” related to the prevention and/or reporting of oil spills and liability for damages resulting from such spills in US coastal waters, and foreign spills reaching the USA. A “responsible party” could be the owner or operator of a domestic or foreign offshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs, along with a variety of public and private damages. Moreover, a party cannot take advantage of liability limits if the spill was caused by gross negligence or wilful misconduct, or if it resulted from violation of a federal safety, construction or operating regulation.

US Outer Continental Shelf Lands Act

The US Outer Continental Shelf Lands Act (OCSLA) extends US jurisdiction to the subsoil and seabed of the OCS, and authorises regulations relating to safety and environmental protection applicable to lessees and permittees operating in the GOM. Under OCSLA, the USA has enacted regulations that require operators to prepare spill contingency plans and establish air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulphur dioxide, carbon monoxide and nitrogen oxides. Violations of lease conditions or regulations related to the environment issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and cancelling leases. 

OCSLA also provides for regulation of pipelines on the OCS, which is characterised as an exclusively federal domain separate from any US state. Transportation of oil or gas by pipeline across or within the OCS is therefore not “interstate” in character and correspondingly not subject to regulation under the NGA (for natural gas) or ICA (for petroleum liquids). Pursuant to Section 5 of OCSLA, OCS pipeline rights-of-way are managed by the BSEE and are subject to open and non-discriminatory access requirements. While FERC has very limited authority over OCS pipelines, it may exercise NGA authority over natural gas pipelines that cross from the OCS into state waters, and ICA authority over movements of petroleum liquids from the OCS into state waters. 

BSEE provides for complaint-based enforcement of OCSLA’s open-access requirements. Remedies for a pipeline’s failure to provide open and non-discriminatory access include orders to provide such access, civil penalties of up to USD10,000 per day, referral for civil action by the US Department of Justice, and the initiation of a proceeding to forfeit the relevant OCS rights-of-way.

US Comprehensive Environmental Response, Compensation and Liability Act

Laws and regulations protecting the environment have generally become more stringent and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault. For example, the US Comprehensive Environmental Response, Compensation and Liability Act (commonly known as CERCLA or the “Superfund” law) imposes liability without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. In what is commonly known as the “petroleum exclusion”, the definition of “hazardous substance” under CERCLA excludes “petroleum, including crude oil or any fraction thereof”. CERCLA liability attaches when three conditions are satisfied:

• the site at which there is a release of hazardous substances is a “vessel” or a “facility” as defined in CERCLA;
• a “release” of a “hazardous substance” from the facility has occurred; and
• the responsible party is within one of the four classes of persons subject to liability under CERCLA, as follows:
1. current owners and operators of the facility;
2. former owners or operators of the facility at the time of the release;
3. any person who arranges for the disposal of a hazardous substance that has come to be located at the facility; and
4. any person who transported hazardous substances to the facility having selected the facility.

Persons who are, or were, responsible for the release of hazardous substances under CERCLA may be subject to joint and several liability for the cost of cleaning up the hazardous substances released into the environment, and for attendant damages to natural resources and the costs of certain health studies. 

The right to develop oil and gas interests in the USA is typically conveyed or governed by an oil and gas lease (whereby an oil and gas exploration company leases minerals from a landowner) and/or a joint operating or unit operating agreement (whereby multiple “working-interest” owners agree on the manner of development for specified land).

Oil and Gas Leases

Under an oil and gas lease, the upstream company (the “lessee”) receives a working interest that survives for as long as the lease remains in effect. The lessee’s working interest is a cost-bearing interest that typically provides the right to drill on the premises and retain the majority of the hydrocarbons extracted therefrom.

Primary and secondary term

Most private leases include a primary and secondary term. The primary term typically extends for a fixed number of years, during which the lessee has the right – but not the obligation – to evaluate the property and conduct oil and gas operations on the land. The lease may terminate if production is not achieved during the primary term, in which case, the oil and gas interests revert to the landowner (the “lessor”). The secondary term extends the term of the lease (for at least a portion of the leased premises) once production begins, generally stated as “for so long thereafter as oil and gas is produced in paying quantities”. States have varying rules regarding the volume of production required to hold a lease; in Texas, marginal production will typically suffice unless the lease specifies a different outcome. 

"Essential" and "defensive" clauses

Common provisions of a US domestic oil and gas lease (often based on the Producer 88 form, which is a standardised oil and gas lease form) include both “essential clauses” and “defensive clauses”. Essential clauses are those that are necessary to cause the transfer of the right to explore for and produce minerals and to accomplish the fundamental purpose of the lease. These include the following.

• The “granting clause” grants the lessee the right to search for, develop and produce oil and gas from the property. In order to be valid, the granting clause must identify, with reasonable specificity, the size of the interest granted, the land covered by the lease, and the substances covered by the lease (which, in most states – with the notable exception of Pennsylvania – can simply state “all minerals” in order to capture all hydrocarbons).
• A “Mother Hubbard” clause states the parties’ intention for the lease to cover all lands owned by the lessor in a specified area, and is included in many modern leases to protect the lessee where the granting clause does not sufficiently describe the intended conveyance.
• The habendum clause describes the term of the lease. Most modern oil and gas leases are “paid-up” leases, meaning there are no payments (or “delay rentals”) required to extend the lease year to year during the primary term.
• The royalty clause describes the payments owed to the lessor. It has recently become important to clarify when (or if) certain post-production costs may be deducted from royalty payments, including distinctions between royalty calculation methods such as “gross value received” (where post-production cost deductions are generally not permitted) versus “at the well” (where reasonable post-production costs may be deducted). 

Given the potential for substantial capital expenditures by the lessee without meaningful or immediate production, modern oil and gas leases commonly include a number of defensive clauses that extend the term of the lease for some period of time without the necessity of production. Typical defensive clauses include the following: 

• a force majeure clause that relieves the lessee from liability for breach if the party’s performance is impeded as the result of a natural cause that could not have been anticipated or prevented; 
• a dry hole clause that permits the lessee to maintain the oil and gas lease after a well is drilled without production (a “dry hole”) by payment of specified delay rentals, or for a short period of time while operations are commenced to drill a new well;
• a continuous operations clause that allows the lessee to extend the lease if drilling was commenced prior to the expiration of the primary term, and providing there is no delay longer than a specified period between expiration of existing operations and new operations; and
• a cessation of production clause that specifies what the lessee must do to maintain the lease if production in paying quantities ceases.

Pugh clauses

In addition to essential clauses and defensive clauses, many oil and gas leases that cover a large acreage position include “Pugh” clauses, which ensure that a lessee does not maintain the entire leasehold area through a single producing well. A Pugh clause states that a producing well will hold only a specified area around that well, and thus, after the primary term, the mineral owner is free to re-lease the remaining land. The clause may take the form of either a vertical Pugh clause – limiting the lease to certain depths or geological formations – or a horizontal Pugh clause, specifying the surface area surrounding a producing oil and gas well that is held by production from such well (often the minimum area prescribed by state spacing rules). Many modern oil and gas leases with sophisticated landowners include both types.

Common law

In many hydrocarbon-producing states, the common law also implies certain covenants that enlarge the lessee’s obligations to the lessor under the lease, in an effort to protect lessors from inequitable leases. Customary implied covenants include:

• the covenant to drill a test well (which requires the lessee to promptly drill a test well on the acreage, but is not relevant in the event of a paid-up lease);
• the covenant to reasonably develop (which requires the lessee to drill as many wells as reasonably necessary to develop a proven reservoir, but only if there is prior production on the acreage and a reasonable expectation of profit for new wells);
• the covenant of further exploration (which requires the lessee to explore undeveloped areas and only applies after hydrocarbons are discovered in paying quantities);
• the covenant to protect against drainage (which requires the lessee to take reasonable action to protect the leased premises against drainage, although there is no duty to drill offset wells if they are likely to be unprofitable);
• the covenant to diligently market (which requires the lessee to diligently seek purchasers at a reasonable price for any oil or gas that is found in paying quantities); and
• the covenant to restore the surface (which requires the lessee to restore the leased premises to a condition reasonably approaching their original condition).

Given the capital-intensive nature of oil and gas exploration and development activities and the inherent risk of drilling a dry hole, oil and gas lessees can – and often do – convey development rights among themselves by sale, swap, farm-out, joint development agreements or other drilling arrangements, all of which can result in multiple working-interest owners in a single lease.

Joint Operating Agreements

A joint operating agreement (JOA) is a contract between two or more parties creating a contractual framework for the sharing of risk and reward for petroleum operations. JOAs are frequently based on a form issued by the American Association of Petroleum Landmen (AAPL), modified most recently in 1989 and 2015.

Although the 2015 AAPL JOA incorporates features relating to horizontal development, it remains common industry practice to utilise the 1989 AAPL JOA and manually adapt the form to reference horizontal development. While the JOA is a complex instrument and a full summary is beyond the scope of this article, certain key provisions from the 1989 AAPL JOA include the following.

• Provisions relating to the interests of the parties, the treatment of unleased mineral interests and the treatment of burdens. Generally, each party is responsible for the burdens it contributes to the agreement, and agrees to indemnify the other working-interest owners for the payment of its share of such burdens.
• Provisions relating to the designation of the operator and its status, authority and liability for operations in the contract area. While an operator is required to operate as a “reasonably prudent operator”, the AAPL JOA includes a broad disclaimer that limits the operator’s liability to damages arising from its own gross negligence or wilful misconduct. There is continuing debate about whether this disclaimer should only apply to “operations” in the field, or whether an operator should be disclaimed from liability for all “activities” conducted under the JOA, including administrative tasks such as the payment of revenues to the non-operating working-interest owners. Under Texas law, the disclaimer has been interpreted broadly, extending beyond operations to include all activities the operator may conduct under the JOA. Thus, it is common for parties to revise the disclaimer to include carve-outs for certain administrative activities for which the parties agree that the operator should be held to a higher liability standard (ie, simple negligence).
• Provisions relating to the drilling and development of the properties. Generally, any party may propose operations on the acreage, subject to an agreed priority if multiple operations are proposed. To encourage development of the area covered by the JOA, these provisions generally require a relinquishment of a party’s interest if it elects to “non-consent” a drilling operation, which typically applies until the consenting parties have recovered a specified share of their costs from production to participate in the operation.
• Transfer restrictions governing the parties’ divestiture of JOA interests. These include, for example, limits to a party’s right to surrender a lease within the contract area without the consent of the other parties, limits to a party’s right to assign less than its entire or an undivided interest in the leases (known as the “maintenance of uniform interest provision” or MUI), and an optional preferential purchase right.
• A “placeholder” section for the parties to propose additional provisions specific to their circumstances. While these provisions vary, some have become so standard over time that they are now considered commonplace (eg, horizontal provisions, priority of operations and operator liens).

Alternative Development Structures

Besides entering into a JOA, two or more lessees may agree upon alternative structures for the joint development and/or acquisition of specified properties, including defining development areas (usually well-defined areas where a specified party is designated as the operator of all operations undertaken by the developing parties), areas of mutual interest (wherein if one party acquires an interest in properties within the area of mutual interest (AMI), then that party must offer a portion to the other party/ies on the same terms) and/or carried interests (wherein one party pays the costs – typically drilling, exploration and operating costs – of the other party up to an agreed cap, usually until a certain dollar amount is spent by the “carrying” party). 

Working-interest owners may also structure joint development through a farm-out agreement, which is a contract whereby an interest in land is conveyed in return for either testing or drilling operations on the land. The “farmor” is the person who provides the acreage and the “farmee” is the person who agrees to test and/or drill in order to obtain an interest in the acreage. Many farm-out agreements include drilling covenants whereby the farmee promises to drill, and can be held liable for the reasonable costs of drilling if they fail to do so. Alternatively, in a farm-out agreement that includes a drilling condition, the farmee only receives an interest in the property if they drill a test well. In such an event, there are no damages for the failure to drill, but the farmee will not receive an interest in the property. 

Similar to a farm-out, another structure to facilitate joint development is a drilling participation arrangement, commonly referred to as the “DrillCo” structure. DrillCo deals typically involve a commitment by the investor to fund an agreed share of capital costs to drill and complete wells in exchange for an undivided interest in the portion of the leasehold acreage required to produce from those wells (namely, a “wellbore” interest). Besides funding its respective ownership interest of drilling costs, the investor may be required to fund a portion of the operator’s share of drilling costs through a drilling “carry”. Once the investor achieves a specified return, the majority of the wellbore interest typically reverts to the operator.

See 2.1 Forms of Private Investment: Upstream and 2.3 Typical Fiscal Terms: Upstream.

The process of permitting oil and gas wells varies across state and federal jurisdictions and tribal lands, with most being designed in some form to protect human health and the environment. Permits for onshore operations are typically required for the use of local roads, drilling, operating the well (subject to ongoing reporting requirements), sediment discharge and erosion control, the potential discharge of toxic substances into the air, and the protection of endangered species and stream crossing. Wells drilled in the waters of the GOM require more extensive permitting overseen by BSEE (ie, new well, bypass and sidetrack, and revisions to the foregoing).

In order to receive the applicable permit, operators must demonstrate an ability to address a well blow-out and worst-case discharge, and newer permit applications for drilling projects now face heightened standards and scrutiny for well design, casing and cementing, and must be independently certified by a professional engineer.

Although there is no separate tax regime applicable to US upstream oil and gas operations, the federal income tax code, federal income tax regulations and the tax codes and regulations of many states have special provisions for the taxation of US upstream oil and gas operations, particularly with respect to the treatment of “intangible drilling and development costs” (“IDCs”) and “depletion”.

IDCs

IDCs are incurred by an operator when drilling or developing an oil and gas well, and can include the costs of drilling, wages, supplies, repairs and fuel. Because these costs are incurred in the development of wells that can provide a benefit to the taxpayer substantially beyond the end of the taxable year in which they are incurred, they are capital in nature and would ordinarily be recovered through depletion over the life of the asset. However, to encourage taxpayers to engage in the risky exploration and development of oil and gas wells, federal income tax law currently allows most taxpayers to elect to expense and immediately deduct IDCs in the year they are incurred.

Depletion

Depletion is a form of cost recovery that allows a taxpayer to recover the capitalised cost of an oil and gas asset over its useful life, and is calculated on a property-by-property basis. Federal income tax law generally provides for two forms of depletion. “Cost depletion” is available to all taxpayers and provides for the recovery of the tax basis in a mineral property as minerals from such property are produced and sold. “Percentage depletion” allows a deduction with respect to oil and gas assets equal to 15% of the “gross income from the property” earned in a particular year.

Although integrated oil companies and oil and gas refiners and retailers are only permitted to take cost depletion, other taxpayers are currently allowed to use the depletion method that results in a larger deduction for a particular year. In practice, percentage depletion can be more beneficial to taxpayers as it may produce deductions in excess of the tax basis.

Proposed Changes

The Biden administration has proposed significant changes to the federal income tax laws and regulations applicable to US upstream oil and gas companies, including requiring IDCs to be capitalised rather than immediately expensed, and eliminating the percentage depletion method. Although it is unclear whether any such changes will be enacted, it is likely that their enactment would have a significant adverse impact on the upstream oil and gas industry.

Other Taxes

In addition to the federal income tax regime, most states and many localities impose income taxes and various other taxes throughout the oil and gas development and production cycle that are applicable to upstream oil and gas operations, including severance, production, ad valorem, property, excise, sales and use taxes. 

Requirements to Hold an Onshore Federal Oil or Gas Lease

Citizenship

Under US Federal Regulations, onshore federal oil and gas leases may only be held by adult US citizens, associations of US citizens (eg, as partnerships and trusts), US corporations and municipalities. At the time the lessee takes its interest in the lease, the lessee must certify to the BLM that it meets the requirements to qualify to hold a BLM lease. The lessee does not need to provide evidence of its qualification at the time of certification, but the BLM may require the lessee to supply evidence that it meets the qualification requirements. The qualification requirements apply not only to leasehold interests (ie, record title interests), but also to other types of oil and gas property interests, such as overriding royalties, production payments, carried interests and net profit interests.

Section 1 of the Mineral Leasing Act and the associated regulations do not permit foreign corporations or non-US citizens to directly own federal oil and gas leases. If a non-citizen wishes to own federal oil and gas leases, it must do so through an agent or “nominee” corporation. Based on guidance from the Department of the Interior, the determinative requirement is that the holder of record title to the oil and gas leases must be a US corporation or US partnership. 

Surety or personal bond

In order to hold a US federal lease, the lessee must also submit a surety or personal bond to the BLM in the amount set out by federal regulations. The purpose of these bonds is to ensure that the lessee complies with the terms of the oil and gas lease and the federal performance standards (eg, completing and plugging wells and reclaiming and restoring lease areas). In most cases, lessees will utilise surety bonds issued by approved surety companies, although personal bonds or letters of credit are utilised in some cases.

Statewide and nationwide bonds

For lessees who own large leasehold acreage positions, statewide and nationwide bonds may be utilised to cover the bonding requirements of multiple leases. The amount of the bonds may be increased if the BLM determines that the lessee poses a greater risk to oil and gas development, including, for example, a history of previous violations or non-payment of royalties. BLM bonds must remain in place and are binding upon the lessee until either an acceptable replacement bond has been filed or all the terms and conditions of the lease have been satisfied.

Requirements to Hold an Offshore Oil or Gas Lease

With respect to offshore oil and gas leases, although complex bonding requirements apply that are in excess of the onshore requirements, lessees are subject to similar qualification requirements under the BOEM regulations as described for the BLM (above), although the BOEM citizenship requirements have been updated to permit US limited liability companies to satisfy the citizenship requirements in certain circumstances.

While the regulation of oil and gas operations at the local government level is generally limited, one notable exception is Colorado, which on 16 April 2019 changed state pre-emption laws and expanded local governments’ jurisdiction over oil and gas within the state. Colorado Senate Bill 19-181 makes three important changes to prior law:

• it increases local government control;
• it elevates health and safety considerations in permitting decisions; and
• it alters pooling, drilling and permitting requirements.

Senate Bill 19-181 was signed into law on 16 April 2019. This bill expands local governments’ jurisdiction over oil and gas within the state, and clarifies that local governments have powers to regulate siting, land and surface impacts, and all nuisance-type issues related to the industry, as well as the ability to inspect facilities and impose fines.

The bill also changes state pre-emption law by empowering local governments to enact regulations that are more protective or stricter than state requirements, and clarifying that the main state-level regulatory body, the Colorado Oil and Gas Conservation Commission (COGCC), does not have exclusive authority over oil and gas regulations; instead, the COGCC shares authority with local governments and other state agencies to regulate oil and gas activities. Consistent with this framework, Senate Bill 19-181 also requires operators to seek permission from the relevant local government before they can obtain a state permit.

Record Title and Operating Rights

The BLM’s administration of federal leases relies on the concepts of “record title” and “operating rights”. The record title-holder is the person or entity who is contractually linked to the government either as the lessee or as its assignee or sublessee, while the person or entity holding the operating rights has the actual authority to conduct operations on the lease. In addition to record title and operating rights, a party may hold other interests, including overriding royalties.

BLM Approval

Depending on the type of interest transferred, BLM approval may be required. BLM approval is required for transfers of record title and for transfers of operating rights (but not overriding royalties). In the absence of BLM approval, any such transfer of record title and/or operating rights will not be recognised by the BLM and is of no effect (and thus may not be binding on third parties). Approval for assignment must be sought from the BLM within 90 days of signing the assignment. While approval is not required for the transfer of interests other than record title or operating rights, all transferees must meet the BLM’s qualification requirements.

Although the transfer approval process is typically perfunctory and is therefore treated as a customary “post-closing” consent in many transactions, the process requires three originally executed copies of the assignments of record title or operating rights to be filed with the BLM on a BLM-approved form. Each assignment must be accompanied by a request for approval, which must be signed by the assignee and dated. Additionally, the assignment and approval request must be accompanied by the filing fee. In an assignment of operating rights, the assignee must also submit the required bond.

This is not applicable in the USA.

See 2.7 Development and Production Requirements.

See 6.5 Material Changes in Law or Regulation.

See 1.1 System of Hydrocarbon Ownership.

This is not applicable in the USA.

This is not applicable in the USA.

See 1.1 System of Hydrocarbon Ownership.

Master Limited Partnerships (MLPs)

Although there is no separate tax regime applicable to US midstream oil and gas operations, the federal income tax code, federal income tax regulations and the tax codes and regulations of many states include special provisions that allow entities engaged in certain specified activities with respect to minerals or natural resources to be publicly traded partnerships, which are commonly referred to as master limited partnerships or MLPs. In the absence of such special provisions, federal income tax law otherwise requires publicly traded entities to be taxed as corporations.

The vast majority of MLPs are found in the midstream space. MLPs are treated as partnerships that do not pay tax at the entity level as long as 90% of their income is “qualifying income”, which includes income derived from the exploration, development, mining or production, processing, refining, transportation and marketing of minerals and natural resources. Rather, the income, gains, losses and deductions of an MLP flow through to its unit-holders. Non-corporate unit-holders of an MLP are also generally eligible for a 20% deduction on the net income passed through from the MLP to such unit-holder under current law.

Proposed Changes

The Biden administration has proposed changes to the federal income tax laws applicable to midstream oil and gas companies. In particular, one tax reform proposal provides that publicly traded partnerships with qualifying income from fossil fuel-related activities should be taxed as corporations for taxable years beginning after 31 December 2026. Notably, that tax reform proposal also includes an increase of the tax rate for all corporations from 21% to 28%. Although it is unclear whether any such changes will be enacted, they could have a material and adverse impact on the midstream oil and gas industry if they are.

US Downstream Oil and Gas Operations

Unlike the tax regimes applicable to US upstream and midstream oil and gas operations, the federal income tax code, federal income tax regulations and the tax codes and regulations of states generally do not have special provisions for the taxation of US downstream oil and gas operations, and such operations would also be subject to taxation by most states and many localities, including with respect to ad valorem, property, excise, sales and use taxes.

This is not applicable in the USA.

This is not applicable in the USA.

This is not applicable in the USA.

Under Section 7(h) of the NGA, the holder of a certificate of public convenience and necessity from FERC may exercise the right of eminent domain over the land or other property necessary to construct pipelines and other infrastructure contemplated by the FERC certificate. To exercise that right, the certificate-holder must file a condemnation action in the US district court for the district in which the condemned property is located or in the applicable state’s court system. The court will then determine the level of just compensation that the certificate holder must provide to the property owner for the condemned property, according to the laws of the state in which the condemned property is located.

Unlike the NGA, the ICA confers no federal eminent domain rights for interstate oil and liquids pipelines.

See 1.4 Principal Hydrocarbon Law(s) and Regulationsfor federal regulation of transportation of hydrocarbons. In general, intra-state pipelines are outside FERC’s jurisdiction. Rather, transportation of hydrocarbons on intra-state pipelines is regulated by state commissions. Regulation of intra-state pipelines varies widely based on the function of the pipeline (eg, gathering, transmission or distribution). 

This is not applicable in the USA.

This is not applicable in the USA.

See 6.2 Liquefied Natural Gas (LNG).

This is not applicable in the USA.

A foreign business must create one or more wholly-owned US entities through which it may acquire the leasehold interests in order to hold an oil and gas interest in a federal lease. However, there is no single, federal system in the USA governing the formation of such entities, and any new entity(ies) will be formed in and administered subject to the laws of a particular state. The state of formation may be the state where the property is owned or business is conducted, but that is not mandatory.

For example, if an entity is organised under the laws of Delaware but conducts commercial business in Texas, then that entity must comply with the relevant laws of both states. Thus, the entity would be formed and do business in accordance with Delaware law, but would take steps to allow it to be recognised and authorised to do business in Texas, and most of its third-party business dealings and property ownership would be governed by Texas law. The choice of where to form a controlling entity, and perhaps form other sub-entities, often turns on key tax considerations.

Committee on Foreign Investment in the US (“CFIUS”)

Through the Committee on Foreign Investment in the US (“CFIUS”), parties to a prospective acquisition, merger or takeover may provide the US president with a voluntary joint notification of an acquisition, merger or takeover by a non-US entity. By submitting the voluntary notification, a transaction with national security implications will undergo review and receive US government approval or disapproval before the transaction is completed. Where parties to a prospective transaction do not provide voluntary notice to CFIUS, the committee has the authority to initiate its own review of the transaction and to recommend to the US president the unwinding of the transaction after it has been consummated.

Once CFIUS has received a completed formal joint notification, it will conduct a 30-day review to determine whether the proposed acquisition could harm the national security of the USA. If the committee determines that the transaction raises significant national security issues, it will undertake a more thorough 45-day investigation, after which time, a report is issued to the US president, who will decide within 15 days whether to block the acquisition.

Foreign Investment in Real Property Tax Act (FIRPTA)

Oil and gas interests are also subject to the Foreign Investment in Real Property Tax Act (FIRPTA) regime, which generally subjects non-US holders of oil and gas interests to federal withholding tax at a rate of 15% of the gross proceeds received upon a disposition of such interests.

On 8 March 2022, President Biden signed Executive Order 14066 (EO 14066), which prohibits imports of crude oil; petroleum; petroleum fuels, oils, and products of their distillation; liquefied natural gas; coal and coal products from the Russian Federation, as well as new investment in the energy sector in the Russian Federation by a United States citizen. 

For the purposes of EO 14066, the Office of Foreign Assets Control defines “Russian Federation origin” to include goods produced, manufactured, extracted, or processed in the Russian Federation, excluding any Russian Federation-origin good that has been incorporated or substantially transformed into a foreign-made product. Imports of other forms of energy of Russian Federation origin not listed above, or imports of non-Russian Federation origin that travelled through the Russian Federation, are not prohibited by EO 14066.

There are a number of federal, state and local laws and regulations relating to environmental quality, including those relating to oil spills and pollution control. These laws and regulations govern environmental clean-up standards, require permits for certain air emissions, discharges to water, underground injection, and solid and hazardous waste disposal, and set environmental compliance criteria. Failure to comply with the relevant laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, and the imposition of injunctive relief.

Waste Disposal

Although oil and gas wastes derived from primary field operations are generally exempt from regulation as “hazardous wastes” under CERCLA, the federal Resource Conservation and Recovery Act (RCRA) and some comparable state statutes, the EPA and various state agencies have limited the disposal options for certain wastes, including hazardous wastes. In addition, many states regulate the handling and disposal of “naturally occurring radioactive materials” (NORM).

Hydraulic Fracturing

Under the federal Safe Drinking Water Act (SDWA), the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities involving the use of diesel fuels and has published permitting guidance addressing the use of diesel in fracturing operations. In addition, the EPA issued guidance regarding federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. Furthermore, numerous states have adopted regulations that require disclosure of at least some of the chemicals in the fluids used in hydraulic fracturing or well-stimulation operations; other states are considering adopting such regulations.

Release of Hazardous Substances

Under CERCLA, liability is joint and several for costs of investigation and remediation, and for natural resource damages and the costs of certain health studies, without regard to fault or the legality of the original conduct, on certain classes of persons, with respect to the release into the environment of substances designated under CERCLA as hazardous substances. Although CERCLA generally exempts “petroleum” from the definition of hazardous substances, petroleum products containing other hazardous substances have been treated as hazardous substances under CERCLA in the past. 

Oil Spills

The OPA amends and augments the oil-spill provisions of the Clean Water Act and imposes duties and liabilities on certain “responsible parties” related to the prevention of oil spills, and damages resulting from such spills, in or threatening US waters or adjoining shorelines. A “responsible party” could be the owner or operator of a facility, vessel or pipeline that is the source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. The OPA assigns liability, which is generally joint and several, without regard to fault, to each responsible party for oil-removal costs and for a variety of public and private damages. Although there are defences and limitations to the liability imposed by the OPA, they are limited.

Methane Emissions

In May 2016, the EPA finalised rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector. However, in September 2020, the EPA amended the 2016 rules to rescind certain methane standards and remove the transmission and storage segments from the oil and natural gas source category for certain regulations. Subsequently, the 2020 amendments were challenged in the courts and, in June 2021, President Biden signed a resolution under the Congressional Review Act that revoked certain portions of the 2020 amendments. Furthermore, on 15 November 2021, the EPA proposed a new rule intended to reduce methane emissions from oil and gas sources. The 2021 proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the Clean Air Act (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines”, creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule. On 11 November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removed an emissions monitoring exemption for small wellhead-only sites and created a new third-party monitoring programme to flag large emissions events, referred to in the proposed rule as “super emitters”. It is unclear when these proposed rules are expected to be finalised. 

Venting, flaring and leaks

In November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring and leaks during oil and gas operations on public lands (the “Waste Prevention Rule”). However, the BLM’s 2016 Waste Prevention Rule was vacated by the US District Court for the District of Wyoming on 8 October 2020, for intruding on the EPA’s authority to regulate methane. California and environmental groups have appealed the decision. In addition, in September 2018, the BLM issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations. The repeal was invalidated by the US District Court for the Northern District of California in July 2020. On 30 November 2022, the BLM proposed new regulations to reduce the waste of natural gas during the production of oil and gas on federal and tribal lands. The proposed rule would require new and existing operators to submit waste minimisation plans with all applications for permits to drill oil wells, and includes a number of specific affirmative obligations that operators would have to take to avoid wasting oil or gas through venting, flaring and leaks. The proposed rule has received over 3,500 public comments, and the final rule may face challenges and legal scrutiny. As a result, future implementation of methane rules by the BLM is uncertain at this time. 

In addition to the federal regulation of methane emissions, several hydrocarbon-producing states have established measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category, including, California, Colorado, Utah, Wyoming, Texas and New Mexico.

Unique Environmental Impacts Associated with Oil and Gas Production

Certain states have also developed tailored regulatory requirements to address unique environmental impacts that could be associated with oil and gas production activities. For example, since 2015, the Oklahoma Corporation Commission has issued several directives establishing volume, depth and disposal rate restrictions for saltwater disposal wells, in order to reduce the potential for seismic activity in "areas of interest" near targeted underground injection sites. In certain instances, the commission has also ordered for specific wells to be "shut in" due to the enhanced seismicity risk associated with underground injection activities. In February 2018, the commission issued additional requirements for operators to have access to a seismic array during drilling activities in certain shale-producing areas, and to comply with certain protocols – including temporary cessation of operations – during seismic events (with basic requirements triggered during earthquakes of magnitude 2.0 or greater).

Additionally, the Railroad Commission of Texas requires applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilising the US Geological Survey, which are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The commission is authorised to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. For example, in December 2021, the commission indefinitely suspended deep produced water disposal in certain areas of the Permian Basin in Texas, and, in March 2022, the commission imposed new restrictions via operator-led response plans that limit the volume and pressure of produced water injected into disposal wells in other areas in the Permian.

See 5.1 Environmental Laws and Environmental Regulator(s).

OPA

Numerous federal and state statutes and regulations, maritime law actions, as well as common law, can impose liability for the release of oil. Of the multiple potentially overlapping laws, the primary vehicle for liability in the event of such a release is the OPA, which applies strict joint and several liability to defined categories of responsible parties.

Coast Guard

Following a release, the Coast Guard will designate one of the responsible parties (typically the majority owner of the vessel or facility that is the source of the discharge) as the responsible party in charge of preparing for, responding to and paying for, clean-up and damages.

Oil Spill Liability Trust Fund

The designated responsible party may receive claims or incur costs that exceed its applicable liability limit or that are otherwise beyond its share of the damages. Nonetheless, the designated responsible party is still required to pay those claims, and may later seek contribution from other responsible parties, or recovery from the Oil Spill Liability Trust Fund, if the designated responsible party has a valid defence to liability or pays claims in excess of any applicable cap on liability.

The responsible party may have other avenues for recovery, such as contractual claims against other parties involved in the operations but, in any event, it may still have to pay claims in excess of its share out of pocket before it pursues recovery from others.

Other Responsible Parties

The OPA also provides for additional entities to be named and held liable as responsible parties based on their status in the operations. The additional responsible parties can include the lessees and permittees of the drilling area, and the owners and operators of the well involved in the incident. Responsible parties under the OPA face liability currently capped at USD137.6595 million for damages, provided certain conditions are met, with no limit on the responsible parties’ liability for removal costs. The limit of liability was adjusted by BOEM on 18 January 2018, to reflect inflation occurring since 1990. The incident involving the Deep Water Horizon drilling rig and its Macondo Prospect well is the only incident to have resulted in damages known to exceed the statutory liability limit for an offshore facility.

Other Laws That Impose Liability

Other laws that impose liability for an offshore release of oil include the Clean Water Act, OCSLA, the National Marine Sanctuaries Act (NMSA), the Refuse Act of 1899, the Migratory Bird Treaty Act, the Endangered Species Act, and the Marine Mammal Protection Act (MMPA). While some of these statutes include limits on liability, the responsible party must prove that it meets the applicable criteria to receive the benefit of such limitations.

State Penalties

Some states bordering offshore waters, including Texas and California, also have oil pollution acts that do not include a cap on damages. In addition to liability for response costs and damages, responsible parties may also be held liable for large civil and criminal fines and penalties under state and federal statutes, including penalties of up to three times the actual cost of removal, and sizeable penalties based on the number of days the violation continued, or the amount of oil released. 

The plugging and abandonment of oil and natural gas wells on state and privately-owned lands are subject to both state and federal regulation. In Texas, for example, a lessee may relinquish a state lease to the state at any time. For federal offshore leases, the BOEM requires that the lessee must permanently plug wells and remove platforms, decommission pipelines and clear the sea floor of all associated obstructions. The BOEM regulations require a lessee to achieve certain financial thresholds to protect US taxpayers from being required to bear any decommissioning costs. 

See “Inflation Reduction Act” in 6.5 Material Changes in Law or Regulation.

The Impact of GHG Emissions and Interstate Natural Gas Pipelines

Clean Power Plan (CPP)

The regulation of GHG emissions has changed substantially over the past three administrations. During the Obama administration, the EPA enacted rules requiring the monitoring and reporting of GHG emissions from a wide variety of major sources under the Clean Power Plan (CPP). These rules included onshore and offshore oil and natural gas production facilities, and onshore oil and natural gas processing, transmission, storage, and distribution facilities. Reporting of GHG emissions from such facilities was required on an annual basis. The Supreme Court limited such reporting to sources that were already regulated under Title V of the Clean Air Act, and stayed implementation of the CPP.

Affordable Clean Energy (ACE) rule

In 2019, the EPA during the Trump administration repealed the CPP and replaced it with the Affordable Clean Energy (ACE) rule, which relaxed certain requirements of the CPP. In January 2021, the Court of Appeals for the District of Columbia Circuit (DC Circuit) vacated the ACE rule, and on 30 June 2022, the Supreme Court reversed the DC Circuit’s decision in West Virginia v EPA. The Supreme Court ruled that the CPP was not within the authority granted to the EPA by the Clean Air Act. The EPA is now restricted to regulating GHG emissions within the “fence lines” of power plants and cannot incentivise the shifting of power generation away from fossil fuel plants to renewable energy sources based solely on its existing authority under the Clean Air Act.

EPA proposed new emissions limits for power plants in May 2023

Against the backdrop of the repeal of the CPP, the legal uncertainty surrounding the ACE rule and the Supreme Court’s decision in West Virginia v EPA, on 11 May 2023, the EPA (under the Biden administration) issued new proposed carbon emission limits and guidelines for new, modified, reconstructed and existing fossil fuel-fired power plants. The new proposed rule purports to reflect the best system of emission reduction and use technology-based improvements, including carbon capture and sequestration and low-GHG hydrogen, to reduce carbon emissions at power plants. The new proposed rule also seeks to repeal its predecessor (ie, the ACE rule) upon approval. Although the final rule is currently expected to be published in the summer of 2024, this new proposed rule is likely to face extensive legal challenges, and whether and when the new proposed rule will take effect is uncertain at this time.

FERC analysis

In March 2021, FERC formally considered the impacts of climate change in its approval of an approximately 87-mile interstate natural gas pipeline project. FERC conducted its analysis by comparing the pipeline project’s reasonably foreseeable GHG emissions to the total GHG emissions in the USA, as well as to the emissions totals in the two states in which the proposed facilities were going to be built. Based on these comparisons, FERC concluded that the pipeline project’s contribution to climate change would not be significant and granted the requested NGA certificate without expressly weighing the climate change impacts against the pipeline project’s benefits.

FERC noted that the newly announced policy would continue to evolve, and that, in future cases where it finds impacts on climate change to be significant, such impacts would be considered along with numerous other factors to determine if the project is required by public convenience and necessity. Thus, the scope of FERC’s NEPA obligations with respect to upstream and downstream GHG emissions and related environmental impacts from interstate natural gas pipelines is currently unsettled and is the subject of ongoing litigation in other FERC proceedings and related judicial appeals.

The New Gas Pipeline Policies

In February 2022, FERC issued its Updated Policy Statement on Certification of New Interstate Natural Gas Facilities and the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (known together as the “New Gas Pipeline Policies”). The New Gas Pipeline Policies would require, among other things, owners and developers to consider the environmental and climate impacts of proposed interstate pipeline projects and set forth how FERC would address GHG emissions in its NEPA analyses. On 24 March 2022, FERC reclassified the New Gas Pipeline Policies as draft policy statements and invited comments by the public.

Certification of LNG Facilities

In contrast to interstate natural gas pipelines, certificating authority over LNG facilities is divided between the DOE, which has authority to permit the import or export of LNG, and FERC, which has authority to permit the building and operating of LNG facilities and interstate pipelines used for imports and exports. Consistent with that division of regulatory obligations, the DC Circuit has found that the NEPA obligations are divided between the DOE and FERC.

NEPA Analyses and GHG Emissions

Partly in response to the uncertainty raised in climate change-related litigation, in June 2019, the US Council on Environmental Quality (CEQ), which is responsible for promulgating NEPA regulations, issued proposed guidance for how agencies should consider GHG emissions and the related climate impacts when conducting NEPA analyses, including that:

• a “but for” causal relationship is not sufficient to render an indirect effect a “reasonably foreseeable” result of the proposed federal action; and
• agencies need not provide a quantitative analysis of effects where the information necessary to do so is unavailable, not of high quality, or so complex as to be overly speculative, nor may they conduct a monetary cost-benefit analysis using “social cost of carbon” estimates or other similar cost metrics.

However, in January 2021, CEQ rescinded the 2019 guidance, and the agency is reviewing the 2016 Greenhouse Gas Emissions and the Effects of Climate Change in NEPA Reviews guidance for potential updates. In the interim, federal agencies may rely upon the 2016 guidance, which directs the agencies to evaluate the effects of a proposed action on climate change.

Public Company Reporting

Additionally, in March 2022, the US Securities and Exchange Commission (SEC) issued a proposed rule that is poised to significantly increase public company reporting on climate risk. If adopted in its current form, the proposed rule would require registrants, including public energy companies, to include detailed information on certain climate-related risks in their registration statements, periodic reports, and financial statements. The required climate-related disclosures would include information about climate-related business risks (in the short, medium and long-term) and related risk management processes, as well as information on Scope 1 and 2 (and in some cases, material Scope 3) emissions. The proposed rules generally follow the frameworks of the Task Force on Climate-Related Financial Disclosures and the Greenhouse Gas Protocol. According to the SEC’s Spring 2022 regulatory agenda issued in June 2022, the proposed climate disclosure rule is scheduled to be finalised in October 2022 in the absence of litigation or other challenges.

See 2.6 Local Content Requirements: Upstream.

See 1.1 System of Hydrocarbon Ownership.

The USA has become a major LNG exporter in recent years. 

Companies seeking to import or export natural gas to or from the USA, via an onshore facility, are required by the NGA to obtain authorisation from FERC and the DOE/FECM. However, the regulatory requirements are different for offshore LNG facilities.

Pursuant to Sections 3(a) and 3(c) of the NGA, FERC authorises the siting, construction and operation of onshore LNG import and export facilities in the USA if FERC finds the project will not be inconsistent with the public interest. In making this determination, FERC conducts a review of the project’s environmental impacts, as required by NEPA.

In conducting its NGA and NEPA reviews, FERC consults with other relevant federal agencies regarding compliance with other statutes and regulations pertaining to the environment, health and safety. The FERC approval process for LNG import and export facilities in recent years has typically taken around 18 to 36 months.

FTA and Non-FTA Imports and Exports

In addition, Section 3(a) of the NGA requires prior approval from DOE/FECM for a person to import or export natural gas to or from the USA. The DOE/FECM evaluates applications to import from or export to countries with which the USA has free trade agreements (“FTA countries”) differently from applications to import from or export to countries without FTAs (“non-FTA countries”). 

Pursuant to Section 3(a) of the NGA, LNG imports from or exports to FTA countries are deemed to be in the public interest, and DOE/FECM is required to authorise applications for such imports or exports without modification or delay. According to the Office of the US Trade Representative, the USA has free trade agreements with 20 countries, including Australia, Canada and Mexico. The DOE/FECM approval process for applications to import from or export to FTA countries in recent years has typically taken between one and five months. 

In contrast, applications to import LNG from or export LNG to non-FTA countries are granted only upon a finding by DOE/FECM that the proposed imports or exports are not inconsistent with the public interest. The public interest standard includes consideration of the price, the need for natural gas, and the security of the natural gas supply. The DOE/FECM approval process for applications to export to non-FTA countries in recent years has generally taken two to three years. There have not been any import licence requests to import LNG from non-FTA countries since 2011.

As pressures across the globe are mounting to reduce GHG emissions to bring annual global temperature increases within the Intergovernmental Panel on Climate Change recommendations, many energy stakeholders have made pledges to reduce or eliminate the carbon emissions associated with their businesses.

CCUS Projects

The 2018 amendment to Section 45Q of the Internal Revenue Code of 1986, as amended, which increased the tax credit available for qualified carbon capture, utilisation and storage (CCUS) projects, in addition to other state and federal incentives intended to encourage advancements in energy transition projects, has spurred a wave of investment in energy transition technologies. Of these technologies, CCUS has possibly received the most attention within the United States, including (i) organic projects; (ii) direct air capture; and (iii) hybrid technologies (eg, extracting energy from biomass). Furthermore, as discussed in 5.5 Climate Change Laws, the EPA’s new proposed carbon emission limits and guidelines for new, modified, reconstructed and existing fossil fuel-fired power plants purports to reflect the best system of emission reduction and use technology-based improvements, including CCUS, to lower carbon emissions at power plants. See 6.5 Material Changes in Law or Regulation for additional information.

CCUS projects may qualify for both 45Q credits and California’s low-carbon fuel standard (LCFS programme), which originated in the state’s Global Warming Act of 2006 and can be “stacked” on 45Q credits. To generate LCFS credits, CCUS projects must be located in California or have produced fuel that is actually delivered to California, and must obtain three approvals:

• a permanence certification (which requires projects to complete post-injection site care, monitoring, and other corrective actions for 100 years);
• a Tier 2 pathway or project-based approval; and
• CARB executive officer approval.

The liability for any leakage in a CCUS project is mitigated through upfront contributions of a percentage of credits to a buffer account. At the time of credit issuance, CCUS projects must contribute between 8% and 16.4% of all LCFS credits to the buffer account, calculated on a risk assessment of the project.

Pore Space

Developers of CCUS projects must also consider real property rights in the context of the applicable project, including the use of the pore space for sequestration. The surface owner typically owns the pore space; as such, any CCUS project would require leases or surface use agreements from the surface owner (similar to an SWD project), but there may be instances where the mineral owner holds those rights, or the mineral owner’s ongoing operations could interfere with the right to use the pore space. The ownership of pore space may vary by state, as many states do not have statutes or case law clearly establishing ownership of pore space.

The US system of oil and gas ownership is unique across the globe, as rights are predominantly owned by private citizens or companies, rather than the state or federal government (see1.1 System of Hydrocarbon Ownership). The development of hydrocarbons is also complicated by the oversight of various agencies at both the federal and state level, which is not found in many other jurisdictions (see 1.2 Regulatory Bodies).

US Council on Environmental Quality (CEQ) Proposed NEPA Greenhouse Gas Guidance and Rollback of 2020 Implementing Regulations

Over the past few years, there has been significant litigation over federal agencies’ responsibility to consider climate change impacts when conducting NEPA reviews of federal activities related to oil and natural gas, and the scope of those obligations remains unsettled.

In July 2020, CEQ issued a notice of final rule-making to amend the NEPA implementing regulations, shortening the time for agencies to conduct their review, eliminating the requirement to evaluate cumulative impacts, and implementing the One Federal Decision policy – rule changes it has since begun reconsidering – and in October 2021, CEQ published the first of two proposed rules amending the 2020 changes. The first proposed rule would essentially restore the detailed permitting and environmental review requirements for new proposed actions that were in place prior to the 2020 rule. These proposed rules were finalised in April 2022.

Biden Administration Updates: Actions on Energy, Environmental and Climate Issues

President Biden has moved quickly to implement his climate and environmental agenda since taking office, ordering numerous actions that could impact the energy and infrastructure sectors. Some of his more notable actions include the following:

• rejoining the Paris Climate Agreement (19 February 2021);
• setting a new nationally determined contribution (NDC) for the USA to achieve a 50–52% reduction in economy-wide GHG emissions by 2030 (22 April 2021);
• issuing an executive order calling for a review of federal environmental regulations, directing federal departments and agencies to review and, where appropriate, add and/or reverse regulations, orders and guidance that conflict with the goal of tackling the climate crisis;
• issuing a temporary pause on new federal oil and gas leases and requiring the US Department of Interior to undertake a comprehensive review of the existing federal onshore and offshore oil and gas leasing programmes, which review to date has resulted in an increased flat royalty rate of 18.75% for new onshore leases, a reduction in acreage held for lease, and the delay or cancellation of certain planned lease sales;
• revoking the permit for the Keystone XL pipeline;
• repealing executive orders imposing time and page limits on NEPA reviews;
• together with the European Union, launching a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030; and
• invoking the Defence Production Act for clean-energy technologies.

New EPA regulations

The Biden administration has also directed federal agencies to consider additional regulation, including new EPA regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound (VOC) emissions from existing operations in the oil and gas sector and, on 15 November 2021, the EPA proposed a new rule intended to reduce methane and VOC emissions from oil and gas sources. The 2021 proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that would never have been regulated under the Clean Air Act (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines”, creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources, and the regulations for new sources would take effect immediately upon issuance of a final rule. On 11 November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removed an emissions monitoring exemption for small wellhead-only sites and created a new third-party monitoring programme to flag large emissions events, referred to in the proposed rule as “super emitters”. It is unclear when these proposed rules are expected to be finalised. Furthermore, as discussed in 5.5 Climate Change Laws, the EPA issued new proposed carbon emission limits and guidelines for new, modified, reconstructed and existing fossil fuel-fired power plants in May 2023. The new proposed rule purports to reflect the best system of emission reduction and use technology-based improvements, including CCUS and low-GHG hydrogen, to reduce carbon emissions at power plants. Although the final rule is currently expected to be published in the summer of 2024, this new proposed rule is likely to face extensive legal challenges, and whether and when the new proposed rule will take effect is uncertain at this time.

Inflation Reduction Act

The Inflation Reduction Act of 2022 (IRA) was passed and signed into law by President Biden in August 2022. The IRA is a climate and energy-focused law that seeks to accelerate investment in alternative energy projects and regulate traditional energy sources. Among other provisions, the IRA includes a methane emissions reduction programme that seeks to reduce methane emissions from the production and distribution of oil and natural gas. The programme provides for funding and imposes fees intended to serve as incentives to improve monitoring and mitigation of methane leaks and is intended to complement the EPA methane standards outlined directly above. For offshore and onshore oil and gas production, processing, storage, transmission and gathering facilities that emit more than 25,000 metric tons of CO₂ annually, the facility will be assessed a fee for each ton of methane above the limit, where annual methane emissions exceed:

• for petroleum and natural gas production facilities, either –
1. 0.2% of the natural gas sent to sale from the facility; or
2. ten metric tons of methane per million barrels of oil sent to sale from the facility;
• for non-production petroleum and natural gas systems, 0.05% of the natural gas sent to sale from the facility; or
• for natural gas transmission facilities, 0.11% of the natural gas sent to sale from the facility.

For 2024, the fee is set at USD900 per ton, increasing to USD1,200 in 2025 and USD1,500 in 2026. An exemption is available based on a determination by EPA that a facility is subject to previously proposed emissions plan standards. The IRA also allows for netting of emissions for facilities under common ownership or control, by reducing the total obligation to account for facility emissions levels that are below the applicable thresholds within and across all applicable segments.

In addition, the IRA significantly increases the value of the Section 45Q tax credits available to CCUS projects that satisfy certain wage and hour requirements to as much as USD180/ton for direct air capture projects. The IRA also extends the deadline for commencing construction of CCUS projects to 2032, and relaxes the annual capture requirements for credit eligibility to 1,000 metric tons for a direct air capture facility, 18,750 metric tons for an electricity generating facility with a capture capacity of at least 75% of the total carbon emissions from such facility, and 12,500 metric tons for all other facilities.