Oil, Gas and the Transition to Renewables 2024 Comparisons

In the US, 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. 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. 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 the interests.

The Lease

The oil and gas “lease” is more of a hybrid 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.

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 migrate from beneath that tract.

However, the rule of capture is not absolute and has been altered in many hydrocarbon-producing states to promote more ordered production. For example, many states have also adopted the doctrine of correlative rights. This doctrine limits the rule of capture when the extraction 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.

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 important effects, particularly in the context of bankruptcy proceedings. 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, dormant estate, or a profit à prendre.

In the US, 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. 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, State and Tribal Land

While private mineral ownership dominates in the majority of hydrocarbon-producing states, the federal, tribal and majority of state governments own property that they may then lease for oil and gas development. The federal government owns about 30% of all onshore lands located in the US 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 state where oil and gas operations occur, but a variety of state, federal and tribal government agencies govern petroleum development activities in the US.

While historically the federal government has left regulatory oversight of onshore oil and gas exploration and production to state governments, public scrutiny about oil and gas operations has increased as hydrocarbon development expands into more urban areas. In response, regulators and legislators at the federal and state levels have taken steps to increase regulation and enhance enforcement against oil and gas operators. 

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 Environmental Protection Agency (EPA) enforces many of the federal environmental statutes and regulations in the US;
• 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, and 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, and reviews proposals to build and operate liquefied natural gas terminals and interstate natural gas pipelines under the Interstate Commerce Act (ICA);
• 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, under the US Department of Transportation (DOT), regulates 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, including 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 impacting waters of the US, 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 EPA, other federal agencies, state and local governments, the responsible parties, and oil-spill response organisations to respond to oil spills at sea;
• the Department of Energy oversees maintenance of the US’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 international boundaries. 

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

• regulation of methane emissions and fees associated with methane emissions;
• disclosure requirements for the chemicals used in hydraulic fracturing fluids;
• permitting guidance specific to oil and natural gas hydraulic fracturing using diesel fuel;
• the management and disposal of water used in waste fluids and stormwater generated by drilling operations;
• regulation and oversight relating to the location and operation of underground injection control wells;
• air-quality impacts with increases in emissions of methane, volatile organic compounds and hazardous air pollutants; and
• public lands and waters available for development.

At the state level, some 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 (see 2.6 Local Content Requirements: Upstream).

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

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 or properties where operations are conducted. 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. 

Due to 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 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.

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 Natural Gas Act (NGA) gives the Federal Energy Regulatory Commission (FERC) regulatory authority over various aspects of natural gas transportation. 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, but not over LNG import and export facilities. Under the ICA, FERC has similar authority over the rates, terms and conditions of service for pipeline transportation of oil and other liquids in interstate commerce. 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 USD1.544 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 USD16,170 per violation per day for failure to comply with FERC orders, and up to USD1,617 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 the Pipeline and Hazardous Materials Safety Administration’s (PHMSA) 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 US, 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.

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 civil and criminal enforcement proceedings, in addition to fines ranging from USD601 (for training violations) up to USD266,015 per day per violation (for pipeline safety violations) and USD2,660,135 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 (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 establishes a broad national framework for protecting the environment. The basic policy underlying NEPA is to ensure that all branches of government consider 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 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 Gulf of Mexico (GOM), as well as the additional technical complexity of offshore production.

Oil Pollution Act of 1990

The 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 US. 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. 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.

Outer Continental Shelf Lands Act

The Outer Continental Shelf Lands Act (OCSLA) extends federal 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 US has enacted regulations that require operators to prepare spill contingency plans and establish air quality standards for certain pollutants. 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. 

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 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 (current owners and operations, former owners and operations at the time of the release, arrangers of hazardous substance disposal, and transporters of hazardous substances).

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 US 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 of the specified land).

Oil and Gas Leases

Under an oil and gas lease, the upstream company (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 (lessor). The secondary term extends the term of the lease 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 an 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.
• 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 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) or “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; 
• 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, provided 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, common law also implies certain covenants that extend 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.

Joint development agreements and joint operating agreements

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

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. 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”); 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

Development areas, areas of mutual interest, and carried interests

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, then that party must offer a portion to the other party 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). 

Farm-out agreements

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. 

“Drillco” structures

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: Upstreamand 2.3 Typical Fiscal Terms: Upstream.

The process of permitting oil and gas wells varies across federal, state and tribal jurisdictions, 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 state tax codes and regulations 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”.

Intangible Drilling and Development Costs

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 taxpayer’s tax basis.

Proposed Changes

The Biden Administration has proposed significant changes to the federal income tax laws and regulations applicable to 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 federal regulation, onshore federal oil and gas leases may only be held by adult US citizens, associations of US citizens (eg, as partnerships and trusts), or 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 partnership.

Surety or personal bond

In order to hold a 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 federal performance standards (eg, completing and plugging wells and reclaiming and restoring lease areas). In most cases, lessees will use surety bonds issued by approved surety companies, although personal bonds or letters of credit are used in some cases.

Statewide and nationwide bonds

For lessees who own large leasehold acreage positions, statewide and nationwide bonds may be used to cover the bonding requirements of multiple leases. The amount of the bonds may be increased if 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 extensive bonding requirements apply that are in excess of the onshore requirements, lessees are subject to similar qualification requirements under BOEM regulations as described for 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.

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, COGCC shares authority with local governments and other state agencies to regulate oil and gas activities. 

Record Title and Operating Rights

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 BLM. Approval for assignment must be sought from 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 BLM’s qualification requirements.

The transfer approval process is typically considered perfunctory and is treated as a customary “post-closing” consent in many transactions, although parties must be careful to follow enumerated steps, including submission of the required bond.

This is not applicable in the US.

See 2.7 Development and Production Requirements.

See 7.4 Material Changes in Law or Regulation.

See 1.1 System of Hydrocarbon Ownership.

This is not applicable in the US.

This is not applicable in the US.

See 1.1 System of Hydrocarbon Ownership.

Master Limited Partnerships

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 certain 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 (MLPs). In the absence of such special provisions, federal income tax law otherwise requires publicly traded entities to be taxed as corporations.

The 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-holders.

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%.

US Downstream Oil and Gas Operations

Unlike the tax regimes applicable to 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 downstream oil and gas operations, and such operations would generally 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 US.

This is not applicable in the US.

This is not applicable in the US.

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 court. The court will then determine the level of compensation that the certificate-holder must provide to the property owner for the condemned property.

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 Regulations for federal regulation of the 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 US.

This is not applicable in the US.

See 7.2 Liquefied Natural Gas (LNG).

This is not applicable in the US.

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 US 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, although it is not mandatory.

Committee on Foreign Investment in the US

Through the Committee on Foreign Investment in the US (CFIUS), parties to a prospective acquisition, merger, or non-passive investment takeover involving a “foreign person” and a “US business” (or, in certain cases, vacant US real estate) may provide the federal government with a joint notification of an acquisition, merger or takeover by a non-US entity. If parties to a prospective transaction within CFIUS’s jurisdiction do not provide notice to CFIUS, the committee may initiate its own review of the transaction and impose conditions on the deal or force divestment post closing. CFIUS has been “calling in” non-notified transactions more frequently than ever, including transactions that closed ten-plus years ago.

Depending on the type of filing submitted, CFIUS’s evaluation of a transaction may be complete within 30 days or up to 90 days. CFIUS’s approval may be contingent on conditions (called “mitigation measures”), for example, restrictions on sourcing Chinese-origin equipment.

Foreign Investment in Real Property Tax Act

Oil and gas interests are also subject to the Foreign Investment in Real Property Tax Act (FIRPTA), 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.

Agricultural Foreign Investment Disclosure Act

Through the Agricultural Foreign Investment Disclosure Act (AFIDA), foreign persons who acquire, dispose of, or hold any interest in agricultural land, which may include certain land acquired alongside oil and gas assets, must file a disclosure with the United States Department of Agriculture’s Farm Service Agency. The ownership threshold to trigger an AFIDA disclosure requirement is a 10% direct or indirect interest held by an individual foreign person (or foreign persons acting in concert) and a 50% direct or indirect interest held by foreign persons not acting in concert. “Any interest” includes “all interest acquired, transferred or held in agricultural lands by a foreign person”, but does not include:

• security interests;
• leaseholds of less than ten years;
• contingent future interests;
• non-contingent future interests which do not become possessory upon termination of the present possessory estate;
• surface or subsurface easements and rights of way used for a purpose unrelated to agricultural production; or
• any interest solely in mineral rights.

In most cases, the relevant acquisition or transfer of interests must be disclosed within 90 days of the completion of the relevant acquisition or transfer. Failure to timely file an accurate and complete disclosure can result in financial penalties of up to 25% of the fair market value of the relevant land.

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; and coal and coal products from the Russian Federation, as well as new investment in the energy sector in the Russian Federation by a US citizen. Furthermore, on 6 April 2022, President Biden signed Executive Order 14071 (EO 14071), which prohibits any new investment in Russia by a US 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.

For the purposes of EO 14071, “new investment” broadly includes “the commitment of capital or other assets for the purpose of generating returns or appreciation”. Although the export or import of goods, services or technology that follow ordinary sale terms to or from Russia do not fall within the definition of “new investment”, the prohibition on the import of Russia Federation-origin energy products pursuant to EO 14066 remains in effect.

Many federal, state, and local laws and regulations relate 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, and 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

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. 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. There are limited defences and limitations to the liability imposed by OPA.

Methane Emissions

Rules governing methane emissions have varied based on the current administration. Most recently, 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 more stringent and create new regulations 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. In addition, the proposed rule would establish “Emissions Guidelines” 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. 

The EPA issued the final rule on 2 December 2023, effective 7 May 2024, strengthening regulations; expanding reduction requirements for new, modified or reconstructed sources; and formalising “Emission Guidelines” for states and tribes when developing standards for existing sources, with existing sources comprising those sources constructed prior to 6 December 2022. State plans are due within two years after the publication of the final rule with the stipulation that states require compliance within three years thereafter. Accordingly, existing sources could have up to five years from the effective date of the rule to comply with state plan requirements. The final rule also creates a new third-party monitoring programme to flag large emissions events, referred to as “super emitters”. 

Venting, flaring and leaks

In November 2016, 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, 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, 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, BLM proposed new regulations to reduce the waste of natural gas during the production of oil and gas on federal and tribal lands. BLM issued the final rule on 10 April 2024, effective 10 June 2024 requiring new and existing operators to either self-certify their commitment to capturing all gas produced or submit waste minimisation plans with all applications for permits to drill oil wells. BLM’s final rule includes a number of specific affirmative obligations that operators will have to take to avoid wasting oil or gas through venting, flaring and leaks. The final rule dropped proposed requirements for more stringent controls on equipment. 

On 2 December 2023, the EPA issued a final rule, discussed above, requiring the phase-out of routine flaring of associated gas from newly constructed wells and creating protocols for optical gas imaging in leak detection. However, on 6 May 2024, the EPA announced that it is reconsidering two technical aspects of the final rule relating to monitoring and emergency operations for flares, which will be open to public review and comment.

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, North Dakota, and New Mexico.

Unique Environmental Impacts Associated With Oil and Gas Production

Certain states, such as Oklahoma and Texas, have also developed tailored regulatory requirements to address unique environmental impacts that could be associated with oil and gas production activities. 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. 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 using 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. 

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 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

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 OPA face liability currently capped at USD167,806,900 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 15 May 2023, to reflect inflation occurring since 2016. The incident involving the Deep Water Horizon drilling rig and its Macondo Prospect well is the only incident known to have resulted in damages exceeding 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, including certain financial assurance obligations. In Texas, for example, a lessee may relinquish a state lease to the state at any time. For federal offshore leases, BOEM requires that the lessee must permanently plug wells and remove platforms, decommission pipelines and clear the sea floor of all associated obstructions.

See “Inflation Reduction Act” in 6.1 Energy Transition Laws and Regulations.

The Impact of GHG Emissions and Interstate Natural Gas Pipelines

EPA finalises new emissions limits for power plants in May 2024

In 11 May 2023, the EPA issued new carbon emission limits and guidelines for new, modified, reconstructed and existing fossil fuel-fired power plants. The EPA issued the final rule on 9 May 2024, effective 8 July 2024, which purports to reflect the best system of emission reduction and to use technology-based improvements, including carbon capture and sequestration and low-GHG hydrogen, to reduce carbon emissions at power plants. The final rule requires coal-fired plants to convert to natural gas co-firing by 1 January 2030 and retire by 2039, or install carbon capture and sequestration technology capable of capturing 90% of CO₂ emissions by 2032, or stop operations by 2032. The final rule repealed the Affordable Clean Energy (ACE) rule. 

Supreme Court blocks EPA Good Neighbor rule

The EPA issued its final Good Neighbor rule on 15 March 2023, effective 14 May 2023, imposing stricter NOx emissions limitations for fossil fuel-fired power plants in 23 states. The states of Texas and Louisiana sued the EPA in the US Court of Appeals for the Fifth Circuit in May 2023, challenging the rule’s applicability. The Fifth Circuit issued a temporary stay on the rule while the merits of the case are heard. On 27 June 2024, the Supreme Court upheld the stay. 

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 US, 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 to transport natural gas to or from LNG facilities. Consistent with that division of regulatory obligations, the US Court of Appeals for the DC Circuit has found that the NEPA obligations are divided between the DOE and FERC.

NEPA Analyses and GHG Emissions

In January 2023, the US Council on Environmental Quality (CEQ) issued interim guidance to assist agencies in evaluating GHG emissions and the climate change effects of proposed actions under NEPA. The interim guidance recommends that such evaluations occur early in the planning process, and that agencies quantify a proposed action’s projected GHG impacts over its lifetime. 

Public Company Reporting

In March 2022, the Securities and Exchange Commission (SEC) issued a proposed rule to significantly increase public company reporting on climate risk. The final rule was issued on 6 March 2024, requiring disclosure of Scope 1 and Scope 2 and exempting GHG emissions disclosures for smaller reporting companies, emerging growth companies, and non-accelerated filers. The final rule is facing numerous lawsuits, which are to be consolidated and heard by the US Court of Appeals for the Eighth Circuit. The rule has been stayed pending these legal challenges.

See 2.6 Local Content Requirements: Upstream.

Federal Legislative Developments

The Inflation Reduction Act

The Inflation Reduction Act of 2022 (IRA) is focused on accelerating investment in the energy transition by providing funding for renewable and low-carbon sources and regulating traditional energy sources. The IRA offers new tax credits for investment in energy transition projects and infrastructure, as well as production of renewable energy and low-carbon fuels, and extends existing tax credits. 

The IRA’s Methane Emissions Reduction Program amends the Clean Air Act and provides funding and imposes fees to incentivise improvements in the monitoring and mitigation of methane leaks. Additionally, funding is dedicated to increasing agency permitting resources and improving stakeholder engagement. 

The IRA also provides that the Secretary of the Interior must hold an offshore oil and gas lease sale during the 120-day period prior to issuing a right-of-way for wind or solar energy development on federal lands and must hold an offshore oil and gas lease sale within one year prior to issuing a lease for offshore wind development on the outer continental shelf. 

Federal Regulatory Developments

National Environmental Policy Act implementing regulations revisions phase 2

CEQ has finalised its Bipartisan Permitting Reform Implementation Rule, revising its regulations for implementing the procedural provisions of NEPA. The revisions provide for an effective environmental review process, ensure full and fair public engagement, enhance efficiency and regulatory certainty, and promote sound agency decision-making. The final rule completes a multiphase rule-making process that CEQ initiated in 2021. The revisions include setting clear one- and two-year deadlines for agencies to complete environmental reviews, and unifying and co-ordinating the federal review process. 

The Bureau of Land Management’s renewable energy and right-of-way programmes

In May of 2024, the Department of the Interior promulgated a final rule updating procedures governing BLM’s renewable energy and right-of-way programmes. The final rule focuses on solar and wind energy generation rentals and fees and expanding agency discretion to process applications for solar and wind generation rights-of-way. As a result, the rule will reduce acreage rents and capacity fees, improve BLM’s application process, and deliver greater predictability as to how BLM will administer future solar and wind project authorisations. 

Department of Energy’s new federal permitting rule and Coordinated Interagency Transmission Authorizations and Permits Program

In April 2024, the Department of Energy (DOE) finalised the Coordinated Interagency Transmission Authorizations and Permits (CITAP) Program to make the federal permitting process for transmission infrastructure more efficient and effective. The programme establishes the DOE as the lead agency to co-ordinate and accelerate federal environmental reviews and permitting processes for qualifying electric transmission facilities. 

Renewable Fuel Standard Program: standards for 2023–2025 and other changes

The EPA has set renewable volume obligations (RVOs) for 2023–2025 in the 2023 renewable fuel standard (RFS) final rule, along with other important regulatory changes impacting Renewable Identification Numbers (RINs). The final rule implements proposed changes to renewable natural gas (RNG)-based RIN generation and separation. The RNG producer is the only party that may generate RINs on compressed natural gas (CNG) and liquefied natural gas produced from biogas. The final rule also provides for partial retroactivity with time to reach compliance. Specifically, biogas regulatory reforms are effective from 1 January 2025 for existing registrants. New facilities registered on or after 1 July 2024 must comply immediately. Parties have approximately 22 months between promulgation and the compliance deadline for the 2024 standards.

Class VI Underground Injection Control permits

Class VI permits allow the injection of carbon dioxide into deep rock formations in connection with the carbon capture, utilisation and storage (CCUS) project pursuant to the federal Safe Drinking Water Act’s Underground Injection Control (UIC) Program. While the EPA has primary permitting and enforcement authority under the UIC Program, the programme is a delegated programme, and three states (North Dakota, Wyoming and Louisiana) have primacy to issue Class VI permits.

State Regulatory Developments

Low Carbon Fuel Standards

The Low Carbon Fuel Standards (LCFS) programme aims to diversify the state’s fuel mix to reduce petroleum dependency and reduce the carbon intensity of California’s transport fuel mix by 20% by 2030, relative to 2010 levels.

In 2018, the LCFS was amended to permit certain CCUS projects to qualify for credits. The CCUS protocol requires projects to complete post-injection site care, monitoring, and other corrective action for 100 years. Several states have also enacted the LCFS programme, including Oregon and Washington.

On 19 December 2023, the California Air Resources Board (CARB) published proposed amendments to its LCFS programme, including to:

• phase out LCFS crediting for RNG projects after 2040;
• impose new limits on RNG injected into the common carrier pipeline network that could severely restrict the eligibility of out-of-state projects to generate LCFS credits; and
• eventually phase out avoided methane crediting for RNG projects. 

See 5.5 Climate Change Laws for additional information.

Upstream and Midstream Oil and Gas Assets Use in Energy Transition

As major oil and gas companies continue to invest in energy transition projects, certain traditional upstream and midstream assets are being utilised in connection with transition projects – most notably for CCUS projects.

Reduction in CO₂ and Environmental Mitigation

Methane emissions can occur at different stages in natural gas production and transportation. Leaks and unintentional releases, and the gas flaring associated with oil and natural gas extraction, cause methane to escape into the air. However, advances in methane detection technology, from satellites and atmospheric monitoring to handheld instruments used in operating facilities, can help operators detect a methane leak and measure emissions more accurately. See 5. Environmental, Health and Safety (EHS) for a discussion of regulations restricting GHG emissions, including methane, from oil and gas operations.   

Laws, Programmes and Incentives Targeting Upstream and Midstream Actors

Many programmes and incentives facilitate upstream and midstream oil and gas actors’ abilities to reduceCO₂ and alleviate impacts to the environment. 

CCUS Tax Credits Under the IRA

Under the IRA Section 45Q (as discussed in 6.1 Energy Transition Laws and Regulations), oil and gas upstream and midstream actors can incorporate CCUS into their operations to reduce their CO₂ profile. Credits are available for a qualifying CCUS project for 12 years from the placed in-service date. Credits go to the entity that owns the carbon capture equipment and then either physically or contractually ensures the capture and permanent storage or use of the CO₂. Equipment owners can elect to transfer all or a portion of the credits to the offtaker who disposes of or uses the CO₂. Credits cannot be further transferred to subcontractors. The construction of the qualified facility and the carbon capture equipment that will be used at the facility must generally begin before 2032. Credits are subject to recapture by the IRS if previously captured CO₂ escapes.

Data from the Global CCS Institute’s (GCCSI’s) 2023 report shows that 198 new carbon capture and storage facilities have been added to the project pipeline since the 2022 report. In 2023, 41 CCS facilities were operating, with 26 in construction and 325 in development.

Low Carbon Fuel Standard Programmes

As discussed in 6.1 Energy Transition Laws and Regulations, California’s LCFS programme – along with those of other states, such as Oregon and Washington, that have similar renewable fuel incentive programmes – sets annual carbon intensity benchmarks on transportation fuels to reduce the carbon emissions in the state. The programme awards credits to CCS projects at oil and gas production facilities and refineries.

RNG/Biodiesel

Traditional midstream and downstream facilities that have been utilised in the production of hydrocarbons are also being converted to RNG processing and/or renewable diesel plants. The processes used to create renewable diesel in the US are most commonly either hydro-processing or hydro-treating, which parallel “cracking” crude oil into gasoline and diesel products. Thus, renewable diesel production facilities may be derived from converted parts of crude oil refineries or complete conversions of refineries.

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 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 US, 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 purport to reflect the best system of emission reduction and use technology-based improvements, including CCUS, to lower carbon emissions at power plants. 

See7.4 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), 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 a saltwater disposal (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.

See 1.1 System of Hydrocarbon Ownership.

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

Companies seeking to import or export natural gas to or from the US, 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 US if FERC finds the project will not be inconsistent with the public interest. In making this determination, FERC also 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 the DOE/FECM for a person to import or export natural gas to or from the US. The DOE/FECM evaluates applications to import from or export to countries with which the US 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 the 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 US 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 the 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.

Stay of Biden Administration’s Pause of Pending Decisions on LNG Exports

In January 2024, the Biden Administration announced a temporary pause on pending decisions on new exports of LNG to non-FTA countries, pending the DOE review of the authorisation, including an assessment of the impact of GHG emissions. In July 2024, the US District Court for the Western District of Louisiana stayed the temporary pause, relying in part on (i) the NGA’s express language that applications are to be processed expeditiously, and (ii) a July 2023 decision by the DOE regarding LNG exports. At the time of writing, it is not clear whether the ruling will be appealed or whether the pause will be reintroduced in a new or different form.

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 (see 1.1 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’s Proposed NEPA GHG 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. 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

The Biden Administration moved quickly to implement its climate and environmental policy, ordering numerous actions that could impact the energy and infrastructure sectors. Some of the more notable actions include the following:

• rejoining the Paris Climate Agreement (19 February 2021);
• setting a new nationally determined contribution (NDC) for the US 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 and directing federal departments and agencies to review regulations, orders and guidance that conflict with the goal of addressing the climate crisis;
• issuing a temporary pause on new federal oil and gas leases and requiring the Department of Interior to undertake a comprehensive review of the existing federal onshore and offshore oil and gas leasing programmes, which 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 Defense Production Act for clean-energy technologies.

New EPA regulations

See 5.1 Environmental Laws and Environmental Regulator(s), 5.5 Climate Change Laws and 6.1 Energy Transition Laws and Regulations(discussing the Inflation Reduction Act).