In the USA, mineral rights are predominantly owned by private citizens or companies, rather than the state or federal government. The US system of private mineral ownership and leasing is more complicated than the systems of most countries, and has shaped many pertinent legal and regulatory issues affecting US hydrocarbon development.
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. Nonetheless, private mineral right ownership is the rule rather than the exception in the USA, and successive generations of buying and selling of the surface and subsurface has created an industry related to opining about the current and historical ownership of oil and gas interests.
It is common in hydrocarbon-producing states for the mineral rights to be severed from the surface rights in the land. Severance often occurs when a property owner sells the surface but retains his or her 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.
Mineral owners often have no industry expertise with respect to exploration and production activities and do not actively develop (and have no intention to develop) their own minerals and, instead, lease those rights to an oil and gas exploration and production company. 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.
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 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 his or her land, even if the oil and gas migrated from neighbouring tracts. Thus, subject to trespass, the ownership in 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.
Furthermore, many states have adopted the doctrine of correlative rights, first defined under Texas law in Elliff v Texon Drilling Company. 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.
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.
The two theories of ownership have wide-ranging effects on the oil and gas industry, which have recently been examined by a host of professionals during the most recent wave of energy restructurings in the USA. 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. Ownership theories across many hydrocarbon-producing states are listed below:
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.
Modern leases may also specifically impose surface use limitations – for example, by requiring the burying of pipelines to a specified depth or that drilling be conducted at specified times and/or at a minimum distance from a residence or other edifice.
While private mineral ownership dominates in the majority of hydrocarbon-producing US states, the federal and most state governments own property which they may 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 (equal to one-eighth of the value of production).
In addition to federal ownership, many Native American tribes own mineral interests within their lands. Often, these lands are owned and controlled by a number of different community and federal agencies. Native American regulation varies considerably across tribes, and the tribes have varying degrees of technical capacity with respect to oil and gas development. Besides tribal regulation, the development of Native American lands falls under the Bureau of Indian Affairs, which was established by the federal government to protect the tribes from fraud and opportunism.
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 Native American land can be complex, and tribal land ownership adds additional 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 both 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, the 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:
At both state and federal levels, recent regulatory initiatives have primarily focused on four key issues related to shale gas 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.
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 properties. What follows is a high-level review of major US laws and regulations affecting the upstream industry.
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" 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. 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, rather than state, treasuries.
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.
Further, 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 NGPA, including the ability to levy civil penalties for rule violations or market manipulation of up to approximately USD1.29 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 USD13,525 per violation per day for failure to comply with FERC orders, and up to USD1,352 per violation per day for most other violations (all of which are subject to annual adjustment for inflation).
Both MARAD and the Coast Guard oversee the operations and licensure of deepwater ports in US waters. Deepwater ports are offshore terminals used to import and/or export oil or natural gas, including LNG. They can consist of both onshore and offshore facilities and are subject to various permitting requirements based on the location and nature of the facilities involved. Under the Deepwater Port Act (DWPA), any individual, corporation, partnership or other association or government entity seeking to own, construct or operate a deepwater port must obtain a licence from MARAD. MARAD jointly reviews licence applications with the Coast Guard, and in so doing consults with other federal agencies and the state (or states) adjacent to the project.
In addition, natural gas deepwater ports – but not oil deepwater ports – must secure approval from the DOE/FE, 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 DWPA.
Pursuant to the DWPA, MARAD’s Notice of Application starts a 240-day window during which MARAD must complete any public hearings. During this time, MARAD and the Coast Guard, in collaboration with other agencies, will complete the NEPA review process, including the development of any Environmental Impact Statements.
Once the application has made it through the federal and state review process and has reached the "record of decision" stage, MARAD will render a final decision based on the applicant’s ability to meet and comply with the criteria set forth in the DWPA and other applicable laws and regulations. A deepwater port licence is not issued contemporaneously with MARAD’s record of decision; rather, it is issued at an unknown later date, upon the applicant’s satisfaction of all conditions imposed by MARAD in the record of decision. As with interstate natural gas pipelines and onshore export facilities, deepwater ports must obtain numerous other state and federal permits and approvals. Complying with those requirements is a condition to licence issuance.
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.
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 USD493 (for training violations) up to USD218,647 (for pipeline safety violations) per day per violation, and USD2,186,465 for a related series of violations.
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 alternatives to 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 the restricting or prohibiting of 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. In the aftermath of the Macondo well blowout in April 2010, BSEE and BOEM implemented new regulations and requirements that add safety measures, increase permit scrutiny and add other requirements and policies for offshore drilling that require lessees to:
On 2 May 2019, BSEE announced revisions to the Well Control Rule, changing 68 of the 342 provisions in the post-Macondo rule and adding 33 more. The new rule reduces the frequency of tests to equipment, including blowout preventers, removes the requirement that BSEE must approve the contractors that oil and gas companies pick to evaluate their equipment, increases the time between inspections, and replaces real-time monitoring requirements with "company-specific approaches". In addition, BSEE clarified that source control, containment and collocated equipment (SCCE) listed in the regulations represent examples of the types of SCCE that may be appropriate in specific circumstances, but are not universally required on all rigs.
The 2019 revisions to the Well Control Rule have been challenged by environmental groups in ongoing federal court litigation.
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, alongside 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.
The US Outer Continental Shelf Lands Act (OCSLA) extends US jurisdiction to the subsoil and seabed of the OCS. It also 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. In contrast, FERC has very limited authority over OCS pipelines, including:
FERC may, however, exercise NGA authority over natural-gas pipelines that cross from the OCS into state waters, and ICA jurisdiction 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.
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:
Persons who are, or were, responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the cost of cleaning up hazardous substances released into the environment, and for attendant damages to natural resources.
The USA is one of approximately 170 member countries of the International Maritime Organization (IMO), a sub-agency of the United Nations that is responsible for improving the safety and security of international shipping channels and for preventing marine pollution from marine vessels. The various international conventions negotiated by the IMO include the International Convention for the Prevention of Pollution from Ships, which imposes environmental standards on the shipping industry relating to oil spills, management of garbage, the handling and disposal of noxious liquids, harmful substances in packaged forms, sewage and air emissions.
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/unit operating agreement (whereby multiple "working-interest" owners agree on the manner of development for specified land).
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. Most private leases include a primary term and a 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 but, in Texas, marginal production will typically suffice to hold a lease (unless the lease specifies a different outcome).
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.
One essential clause is the "granting clause", which 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 the Dunhamrule in Pennsylvania, which provides a rebuttable presumption that a reservation in a conveyance for "minerals" without any specific mention of natural gas or oil does not include natural gas or oil – can simply state "all minerals" in order to capture all hydrocarbons).
To protect the lessee where the granting clause does not sufficiently describe the intended conveyance, many modern leases also include a "Mother Hubbard" clause, which states the parties’ intention for the lease to cover all lands owned by the lessor in a specified area.
Other essential clauses include the habendum clause, which describes the term of the lease, and the royalty clause, which describes the payments owed to the lessor. 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.
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 force majeure, dry hole provisions, well completion clauses, continuous operations clauses, shut-in clauses, pooling and unitisation clauses, and cessation of production clauses.
A force majeure clause 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. While a force majeure clause may be drafted in an expansive manner, courts often construe the clause narrowly.
A dry hole clause 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 well completion clause allows the lessee to continue drilling operations that began prior to the expiration of the primary term so long as there is no extended interruption in the operations.
A continuous operations clause allows the lessee to extend the lease if drilling was commenced prior to the expiration of the primary term, and as long as there is no delay longer than a specified period between expiration of existing operations and new operations.
A cessation of production clause specifies what the lessee must do to maintain the lease if production in paying quantities ceases. Typically, a cessation of production clause takes the form of a temporary cessation of production clause that allows the lease to be maintained as long as production does not cease for more than an agreed period of time.
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/released land. The clause may take the form of either a vertical or horizontal Pugh clause, with many modern oil and gas leases with sophisticated landowners including both types.
A vertical Pugh clause limits the lease after the primary term to certain depths or certain geological formations. A common iteration of a vertical Pugh clause limits the depths held by production from the surface to the deepest producing formation established by the end of the primary term. A horizontal Pugh clause specifies the surface area surrounding an oil and gas well held by such well, often the minimum area prescribed by state spacing rules.
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:
Given the capital-intensive nature of oil and gas exploration and development activities and the inherent dry hole risk (ie, the risk that expenses are incurred to drill a non-productive well), 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.
In Texas, in the absence of an express contractual agreement to the contrary, any of the co-lessees may drill for and produce oil and gas on jointly owned lands without the consent of the other co-owners. However, the operating co-tenant assumes the risk of a dry hole and must account to the other non-operating co-tenants for their share of production, after the operating co-tenant has recovered out of production the cost of drilling for, producing and operating the jointly-owned property.
The joint operating agreement (JOA) is the typical solution to the above co-tenant problem, and 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.
While the JOA is a complex instrument and a full summary is beyond the scope of this article, the following is a high-level review of several key sections in the JOA. The 2015 AAPL JOA incorporates features relating to horizontal development; however, it remains common industry practice to utilise the 1989 AAPL JOA and adapt the form manually to reference horizontal development, so the following summary is based on the 1989 form.
The first substantive article addresses the interest of the parties, and contains provisions relating to 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. If additional encumbrances are placed on a party’s lease/s that are not reflected on Exhibit A to the JOA, then those "subsequently created burdens" are the sole responsibility of the burdened party.
Next, the JOA sets forth each party’s obligations and rights in the event of a loss of title to any interests located in the contract area. The operator is generally required to examine title prior to commencing the drilling of a well, and is responsible for obtaining title curative, but the other JOA parties are responsible for their pro rata share of the costs of obtaining the required curative matter. If title is determined to be "lost", the loss can be allocated as either an "individual loss" or a "joint loss", depending on who contributed the applicable leases.
The AAPL JOA also contains 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 out of 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 in Reeder v Wood County Energy, LLC to extend 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). In the absence of a complete sale by the operator or an event of insolvency, once appointed, it is difficult to remove the operator since removal requires "good cause" (ie, gross negligence, wilful misconduct and/or material breach of the JOA).
The AAPL JOA also includes provisions relating to the drilling and development of the properties, which specify the remedies if a party elects not to participate in a proposed operation. Under the AAPL JOA, any party may propose operations on the acreage, subject to an agreed priority if multiple operations are proposed.
To encourage development of the Contract Area, the AAPL JOA provides for the relinquishment of a party’s interest if it elects to "non-consent" a drilling operation. This relinquishment typically only applies until the consenting parties have recovered from production a specified share of their costs to participate in the operation (typically, 200% to 400% of the costs paid to drill, complete and equip the well, plus 100% to 200% of operating and equipment expenses).
Under the AAPL JOA, the operator also has the option – but not the obligation – to market hydrocarbons for the non-operated working-interest owners in the event they fail to make other marketing arrangements.
In order to maintain uniform ownership and ensure the other working-interest owners have input with respect to new partners in the contract area, the AAPL JOA includes transfer restrictions governing the divestiture of JOA interests. For example, the JOA limits a party’s right to surrender a lease within the contract area without the consent of the other parties, and requires a party obtaining a renewal or extension of a lease to offer the other parties their proportionate share of such lease. The AAPL JOA also limits 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 includes an optional preferential right to purchase, which provides the counterparty with the first right to purchase the property included within the contract area if the other party elects to sell its interest.
While the JOA body provides a relatively robust and useful framework to facilitate joint development by working-interest owners, the drafters understood that specific circumstances often require a more tailored approach that cannot adequately be defined in a form agreement. Thus, Article 16 was included as a placeholder for the parties to propose additional provisions specific to their circumstances. While these provisions vary, over time some Article 16 provisions have become so standard in the industry that they are now considered commonplace (eg, horizontal provisions, priority of operations and operator liens).
Besides entering into a JOA, two or more lessees may agree upon alternative structures for the joint development/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 (if one party acquires an interest in properties within the AMI, then that party must offer a portion to the other party/ies on the same terms) and/or carried interests (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 the 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 he or she drills a test well. In such an event, there are no damages for the failure to drill, other than the farmee not being entitled to 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 is also often 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 reverts to the operator.
The DrillCo structure may be attractive to the operator, as it allows the company to develop assets and add new cash flow streams with reduced capital outlay and, typically, no additional balance sheet debt. From an investor’s perspective, on the other hand, the deals can be attractive in that they permit exposure to targeted shale basins, increased technical oversight (either through a development programme or qualified well criteria), and collateral support beyond what is typical when investing in other portions of a company’s capital structure.
See 2.3 Typical Fiscal Terms Under Upstream Licences/Leases.
The process of permitting oil and gas wells varies across state and federal 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, the protection of endangered species and stream crossing. Wells drilled in the waters of the Gulf of Mexico require more extensive permitting overseen by BSEE.
There are several different types of BSEE operational permit, including:
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 the petroleum industry, 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 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 laws allow most taxpayers to make an election to expense and immediately deduct IDCs in the year they are incurred.
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 the product of 15% times 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 allowed to use the depletion method that results in the 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.
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, including severance, production, property, excise, sales and use taxes.
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 be qualified 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.
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.
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.
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 the same qualification requirements under the BOEM regulations as described for the BLM above.
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:
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 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.
The BLM’s administration of federal leases relies on the concept of record title. The record title-holder is the person or entity who is contractually linked to the government either as lessee or as its assignee or sublessee. In addition to record title, a party may hold other interests, including operating rights and/or overriding royalties.
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.
While 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. A separate application is required for each assigned lease. In an assignment of operating rights, the assignee must also submit the required bond.
This is not applicable in the USA.
See 2.7 Requirements for a Licence/Lease-Holder to Proceed to Development and Production.
See 6.4 Material Changes in Oil and Gas Law or Regulation.
See 1.1 System of Petroleum Ownership.
This is not applicable in the USA.
This is not applicable in the USA.
See 1.1 System of Petroleum Ownership.
Although there is no separate tax regime applicable to the petroleum industry, 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. Absent such special provisions, federal income tax law otherwise requires publicly traded entities to be taxed as corporations.
Although upstream and certain other energy related businesses can qualify to be MLPs, 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 so 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 and non-corporate unit-holders of an MLP are generally eligible for a 20% deduction on the net income passed through from the MLP to such unit-holder under current law.
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.
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 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.
This is not applicable in the USA.
This is not applicable in the USA.
See 6.2 Liquefied Natural Gas (LNG) Projects.
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 thereunder, often turns on key tax considerations.
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 under Exon-Florio 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 or not to block the acquisition.
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 air, 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.
Although oil and gas wastes are generally exempt from regulation as "hazardous wastes" under 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).
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 published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. In addition, the EPA has issued guidance regarding federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. Furthermore, some states have adopted regulations that require disclosure of the chemicals in the fluids used in hydraulic fracturing or well stimulation operations; other states are considering adopting such regulations.
Under CERCLA, liability is joint and several for costs of investigation and remediation and for natural resource damages, 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.
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 liable "responsible party" could be the owner or operator of a facility, vessel or pipeline that is a 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 liable 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.
In May 2016, the EPA finalised rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector. Although the rules remain in effect, in August 2019 the EPA issued a proposed rule to rescind the methane requirements for certain sources in the production and processing segments of the oil and gas industry; the rule-making has not been finalised. 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; however, in September 2018, the BLM issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations. This repeal is the subject of pending legal challenges.
Despite the recent roll-back of federal regulations of methane emissions, several hydrocarbon-producing states have established similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category.
On 26 March 2020, EPA issued a temporary policy regarding enforcement of environmental legal obligations during the COVID-19 pandemic that applies retroactively beginning on 13 March 2020 (the “EPA Policy”). EPA will exercise enforcement discretion for certain noncompliance covered by the EPA Policy and resulting from the COVID-19 pandemic. Under the EPA Policy, EPA does not expect to seek penalties for noncompliance of routine obligations (specifically, compliance monitoring, integrity testing, sampling, laboratory analysis, training, and reporting or certification) in situations where EPA agrees that COVID-19 was the cause of the noncompliance and the business provides supporting documentation to EPA upon request.
The EPA Policy does not:
Nine states’ attorneys general and a coalition of environmental groups have sued EPA in federal court over the EPA Policy and that litigation is ongoing.
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. The Commission is also considering new restrictions that could limit the volume and pressure of produced water injected into disposal wells.
See 5.1 Principal Environmental Laws and Environmental Regulator(s).
Numerous federal and state statutes and regulations, maritime law actions, as well as common law, can impose liability for a release of oil in the GOM. 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.
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.
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 then 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.
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 USD75 million for damages, provided certain conditions are met, with no limit on the responsible parties’ liability for removal costs.
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 (ESA) 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.
Some states bordering the GOM, including Texas, 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 sizable penalties calculated based on the number of days the violation continues 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.
Although the USA does not have extensive federal climate change legislation currently in effect, climate change legislation or regulations restricting emissions of greenhouse gases (GHGs) could be implemented. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.
The EPA also requires the reporting of GHG emissions from specified large GHG emission sources, including 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 is required on an annual basis.
In May 2016, the EPA finalised rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector. 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. In September 2018, the BLM issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations. This repeal is the subject of pending legal challenges.
Several states have enacted similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category, including Pennsylvania, Ohio, Colorado, California and North Dakota. Other hydrocarbon-producing states, such as New Mexico and Texas, have signalled their intention to implement similar regulatory measures to address methane emissions.
Finally, procedural laws such as NEPA are increasingly being used to impact decision-making about activities that could potentially have an impact on climate. In August 2017, the US Court of Appeals for the DC Circuit (DC Circuit) in Sierra Club et al v FERC vacated and remanded a certificate that FERC issued for a 685.5-mile interstate natural gas pipeline because the agency failed to consider in its NEPA analysis the downstream, indirect greenhouse gas emissions associated with the combustion of natural gas.
The DC Circuit explained that the downstream indirect emissions were reasonably foreseeable, because the record indicated that the natural gas would be combusted at three downstream power plants. On remand, FERC reissued the pipeline certificate and provided an analysis of the downstream, indirect greenhouse gas emissions. However, FERC explained that it did not have a reliable method of defining the environmental impact caused by those emissions. FERC’s remand order was not appealed. The scope of FERC’s NEPA obligations with respect to upstream and downstream greenhouse gas 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.
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 LNG facilities and interstate pipelines used for the 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.
Climate change-related NEPA obligations have similarly impacted upstream oil and gas activities. In March 2019, the US District Court for the District of Columbia in WildEarth Guardians et al v Zinke et alhalted the BLM from authorising new oil and gas drilling on approximately 300,000 acres of land in Wyoming due to the failure of the BLM to adequately address the impact of drilling on climate change. The court did not invalidate leases issued by the BLM, but required the government to further evaluate climate change-causing emissions from drilling as well as downstream impacts from the use of hydrocarbons and the cumulative impact of lease sales. Requiring increased NEPA analysis on climate change could impact the rate at which new drilling activities are authorised on federal lands.
Partly in response to the uncertainty raised in climate change related litigation, in June 2019, the White House’s Council on Environmental Quality (CEQ), which is responsible for promulgating NEPA regulations, issued proposed guidance for how agencies should consider greenhouse gas emissions and the related climate impacts when conducing NEPA analyses, including that (i) a “but for” causal relationship is not sufficient to render an indirect effect a “reasonably foreseeable” result of the proposed federal action and (ii) 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 conduct a monetary cost-benefit analysis using "social cost of carbon" estimates or other similar cost metrics.
In addition, in January 2020, CEQ issued a proposed rule-making to amend the NEPA implementing regulations, intended to streamline the environmental review process. The proposed rules would shorten the time for review as well as eliminate the requirement to evaluate cumulative impacts, which may impact the requirement to evaluate the potential impact of a project on greenhouse gas emissions and climate change.
See 2.6 Local Content Requirements Applicable to Upstream Operations.
See 1.1 System of Petroleum Ownership.
The USA has become a major LNG exporter in recent years. According to the US Energy Information Administration (EIA), in 2017 the USA exported more natural gas than it imported for the first time since 1957. The EIA reports that the USA repeated that natural gas net-export trade balance again in both 2018 and 2019, with US LNG exports reaching a record high of approximately 1,819 Bcf delivered to 37 countries in 2019. In its 2020 Annual Energy Outlook, the EIA reported that LNG exports are expected to continue to increase through 2030, with the USA expected to remain a net LNG exporter through 2050.
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 Department of Energy’s Office of Fossil Energy (DOE/FE). 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. FERC authorises the siting, construction and operation of such facilities if it 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 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; however, approval timelines have become increasingly shorter in the 2019-20 timeframe with one project obtaining approval in under eight months.
As noted in 6.4 Material Changes in Oil and Gas Law or Regulation, FERC and several other federal agencies signed a memorandum of understanding in an effort to streamline the regulatory process for LNG facilities.
In addition, Section 3(a) of the NGA requires prior approval from DOE/FE for a person to import or export natural gas to or from the USA. The DOE/FE evaluates applications to import or export to or from countries with which the USA has free trade agreements (FTA countries) differently from applications to import or export to countries without FTAs (non-FTA countries).
Pursuant to Section 3(a) of the NGA, LNG imports or exports to or from FTA countries are deemed to be in the public interest, and DOE/FE 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/FE approval process for applications to import or export to or from FTA countries in recent years has typically taken between one and five months.
In contrast, applications to import or export LNG to or from non-FTA countries are granted only upon a finding by DOE/FE 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/FE approval process for applications to export to non-FTA countries in recent years has generally taken two to three years. As reflected on the DOE/FE’s website, there have not been any import licence requests to import LNG from non-FTA countries since 2011.
In July 2018, the DOE issued a final rule revising its regulations to expedite its approval of small-scale exports of natural gas (for applications to export up to 0.14 billion cubic feet per day) to non-FTA countries by deeming such exports to be in the public interest. There is also a proposed bill in congress to codify the DOE’s proposed rule.
LNG facilities must also obtain various other permits and approvals, including water-related and air-related permits, from federal and state regulatory agencies.
See 6.4 Material Changes in Oil and Gas Law or Regulation.
Over the last several years, as a wave of restructurings has swept through the industry, many upstream and midstream companies have started to re-evaluate their current agreements, particularly their midstream agreements.
In the Sabine Oil & Gas Chapter 11proceeding, an upstream provider argued that it should be permitted to reject its midstream contracts (namely, gathering agreements with alleged above-market gathering fees). Prior to Sabine, it was commonly understood in the industry that gathering agreements were “covenants running with the land”. However, in Sabine, the upstream company challenged the conventional thinking and the rejection was permitted despite the assertions by counsel for the midstream entities that such contracts were, on the face of it, expressly written to include covenants that “run with the land”, and as such were not contracts that could be rejected (at least in their entirety).
On 3 May 2016, the court ruled that the dedication and recitals were not dispositive. Rather, the court concluded that covenants did not run with the land because the covenants did not in fact “touch and concern” the land, and because, to the extent that horizontal privity is required under Texas law, the parties lacked privity of estate.
The court concluded that the “right to transport or gather produced gas” (as dedicated under the Sabineagreements) was not a valid real property interest recognised by Texas law. Rather, the court found that the dedication provisions related to produced hydrocarbons that had been severed from the real property (as opposed to minerals in the ground). The court therefore concluded that the dedication language did not “touch and concern” the land.
Several subsequent bankruptcy cases have pushed back against the Sabine ruling in an apparent return to the pre-Sabine conventional understanding that gathering agreements do create covenants running with the land.
In the Badlands Energy, Inc. Chapter 11 proceeding, the judge found that the requisite elements to create a covenant were met. In distinguishing Sabine, the Badlands court noted that the dedications in the agreements before it related to “reserves in and under […] the leases” and therefore touched and concerned the minerals in place, a real property interest. The court further held that the privity requirement under Utah law was satisfied by the burden placed on Badlands real property interests and the floating easement over leases and lands in which Badlands had an interest.
Likewise, in In re Alta Mesa Res., Inc., the court found that the agreements the debtor wished to reject similarly created covenants which prevented such rejection. In focusing on the nature of the debtors leasehold interest as compared to the mineral estate at issue in the Sabine case, the court held that both (i) the use by the gatherer of the surface easement to build a gathering system that enhanced the leasehold value and (ii) the imposition of costs and restrictions on the lease which diminished its value were sufficient to satisfy the touch and concern requirement of Oklahoma law.
The court also found that the requisite privity of estate was satisfied, rejecting the idea that surface easements only create privity as to the surface estate, because “surface easements spring directly from [the] leasehold mineral interests”.
While Badlands and Alta Mesa served to limit the Sabine holding, both cases stopped short of outright rejecting it. Viewed together, thesedecisions provide several factors to consider when assessing how courts may analyse the rejection of a midstream agreement, as set out below.
US Council on Environmental Quality (CEQ) Proposed NEPA Greenhouse Gas Guidance
As indicated above, 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. Partly in response to this uncertainty, in June 2019 the CEQ – which is responsible for promulgating NEPA regulations – issued proposed guidance for how agencies should consider greenhouse gas emissions and the related climate impacts when conducting NEPA analyses.
The CEQ guidance document includes the following proposals:
FERC Revises Return on Equity Policy for Gas and Oil Pipelines
In May 2020, FERC issued a policy statement on determining the return on equity (ROE) component of the cost-of-service transportation rates for FERC-jurisdictional natural gas and oil pipelines (ROE Policy Statement). In general, to establish natural gas and oil pipelines’ transportation rates, FERC utilises cost-of-service rate-making principles under which a jurisdictional entity’s rates are designed based on its cost of providing service, including an opportunity to earn a reasonable rate of return on the entity’s investments. While FERC had previously relied exclusively upon the discounted cash flow (DCF) methodology to determine natural gas and oil pipeline ROEs, FERC will now average the results of the ROEs produced by the DCF and capital asset pricing model methodologies.
Because most pipeline companies are wholly-owned subsidiaries and their common stock is not publicly traded, FERC utilises a proxy group of publicly traded entities with similar risk to set pipeline ROEs. It has become increasingly difficult to develop representative proxy groups in recent years for various reasons, including significant consolidation in the industry. Accordingly, FERC addressed this difficulty in the ROE Policy Statement by clarifying various issues with respect to proxy groups.
FERC retained its existing proxy group criteria, to include in its proxy groups for pipeline ROE analyses only companies that meet the following criteria:
FERC has historically found that a company meets the “high proportion” standard if the pipeline business accounts for 50% of its assets or operating income over the most recent three-year period. In the Pipeline ROE Policy Statement, FERC explained that it will continue to apply the high-proportion criterion flexibly on a case-by-case basis, including relaxing the 50% requirement in rate proceedings where there are less than five companies eligible for the proxy group. As an additional way to address the ongoing decline in companies eligible for pipeline proxy groups, FERC stated that it will now consider the inclusion of Canadian companies that otherwise meet the criteria.
PHMSA Finalises Gas and Hazardous Liquids Pipeline Safety Rule-makings
In October 2019, PHMSA finalised two pipeline safety rule-makings for natural gas and hazardous liquids pipelines respectively. In the final rule for natural gas pipelines, PHMSA addressed congressional mandates from the Pipeline Safety Acts of 2011 and 2016 and public input on PHMSA’s April 2016 notice of proposed rule-making. Under the final rule, PHMSA mandates a process for operators of previously-untested natural gas transmission pipelines to determine the material strength of their pipelines by reconfirming the maximum allowable operating pressure (MAOP), and PHMSA also enacted reporting requirements for instances where MAOP is exceeded.
The final rule also addresses the assessment of certain pipelines outside high-consequence areas, increased integrity management programme requirements, and increased record-keeping requirements. In the final rule for hazardous liquids pipelines, PHMSA increased the reporting and inspection requirements applicable to operators of hazardous liquids pipelines. Specifically, PHMSA expanded reporting requirements to operators of liquid gravity and rural gathering hazardous liquid pipelines. In addition, PHMSA’s final rule requires hazardous liquids pipeline operators to inspect pipelines affected by extreme weather and natural disasters.
PHMSA Finalises Rule Authorising Transportation of LNG by Rail Tank Car
In June 2020, PHMSA finalised a rule, in consultation with the Federal Railroad Administration, authorising the transportation of LNG by rail tank car. The final rule permits the bulk transportation of LNG in DOT-113C120W9 (DOT-113) specification tank cars with enhanced outer tank requirements and additional operational controls.
The final rule requires remote monitoring of the pressure and location of LNG tank cars. In order to enhance braking capability, the rule requires a two-way end of train or distributed power system when a train is transporting 20 or more tank cars of LNG in a continuous block or 35 or more tank cars of LNG in the entire train. The rule also requires railroads to conduct route risk assessments to evaluate safety and security in light of the potential for LNG shipments.
California Assembly Bill No 1057
Governor Gavin Newsom signed Assembly Bill No 1057 (AB 1057) into law on 12 October 2019, making similar, but less sweeping, changes to the state’s oil and gas regulations as the Colorado legislation discussed above. AB 1057 renamed the state’s oil and natural gas agency from the Division of Oil, Gas, and Geothermal Resources to Geologic Energy Management Division, symbolising a shift in the regulator’s priorities. AB 1057 specified that the newly renamed regulator was to focus on “protecting public health and safety and environmental quality, including reduction and mitigation of greenhouse gas emissions”. Noteworthy changes in the state resulting from the passage of AB 1057 and other recent regulatory actions include the following.
US Council on Environmental Quality (CEQ) Proposed NEPA Streamlining Rule
As indicated in 5.5 Climate Change Laws, 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 January 2020, CEQ issued a proposed rule-making to amend the NEPA implementing regulations, partly in response to the uncertainty surrounding the requirements for reviewing climate change impacts, but also to streamline the environmental review process. The proposed rules would shorten the time for agencies to conduct their review as well as eliminate the requirement to evaluate cumulative impacts, which may impact the requirement to evaluate the potential impact of a project on greenhouse gas emissions and climate change. In addition, the proposal would make the following key changes to the regulations:
CEQ solicited public comments on the proposal and the comment period closed in March 2020. As of June 2020, the rule-making process to update the NEPA regulations is ongoing.
Uncertainty, Risks and Opportunities Abound in the Energy Sector
In some respects, “uncertainty” has always been the legal industry’s bread and butter. One of a lawyer’s primary tasks is to help clients identify potential risks and opportunities and take steps to diminish the former while expanding the latter.
In 2020, however — for the US oil and gas industry, in particular — the degree of uncertainty and the nearly immeasurable consequences have taken on new levels of meaning. Price volatility caused by disputing OPEC+ nations, the COVID-19 global pandemic and related damage to the world economy (including a drop in demand for fuel and other petroleum-based products), and the increasing drumbeat of climate change lawsuits have set the industry’s gains of 2019 into sharp relief. Last year’s opportunities – eg, increased infrastructure development fuelled by expanding economies and global travel – and challenges – including the impact of increasingly destructive weather events on facilities, tit-for-tat tariff disputes between the United States and China, and state-law driven mineral rights issues – pale in comparison to current events.
In uncertain times, however, there are always opportunities, and such opportunities typically involve some form of change. Although there is a natural tendency for companies to hunker down, limit spending, and focus on the core mission during times of stress, those that take this period of “sheltering in place” to build flexibility into their organisations and operations will be better prepared to identify and pivot towards emerging business opportunities.
As oil and gas and oilfield service companies look ahead to the next 12 months, they must assess and address a number of key challenges. Among these are the increased volatility of oil and gas prices, coupled with lowered demand and near-capacity storage; COVID-19 and its impact on operations; the deregulation agenda of President Donald Trump; and ongoing opposition by environmental non-government organisations (ENGOs) to exploration and production (E&P) operations and infrastructure development.
Price Volatility: A Perfect Storm of Prior Success, International Competition and Lowered Demand
In 2019, the word that best characterised the oil and gas industry in the US Gulf Coast region and the Permian Basin was “leap”. Demand for US petroleum products was at or near an all-time high, as were production, infrastructure and distribution capacity. Among other markers, exports had bounced back beyond previous levels following the hurricanes of 2017, new oil pipelines and deepwater crude facilities had been announced, and the number of Very Large Crude Carriers (VLCCs) scheduled to load medium-sour crude was at a record level. Our firm, in particular, noticed a significant uptick in discussions involving the development of liquid export terminal facilities, LNG liquefaction facilities, chemical and natural gas production complexes, pipeline construction, acquisition and joint ventures, and power-plant construction throughout the Gulf Coast.
The impact of the USA's new role as a global energy exporter
As the United States became more energy-independent and shifted into a new role as a global exporter rather than an importer of petroleum-based fuel, OPEC+ countries responded by expanding and/or opening up their own capacity in an effort to dampen US progress in this arena. Then, as the economic consequences and reduced demand for oil caused by COVID-19 lockdowns began to spread, Russia and Saudi Arabia initially locked horns, unable to agree on terms for a mutual reduction of output. In fact, in March 2020 Saudi Arabia actually increased daily output to roughly 12 million barrels per day, boosting exports and lowering prices (“Explainer: Big cuts in oil production from OPEC and others”, Reuters, 13 April 2020). The resulting glut caused prices to fall as low as USD23 per barrel for Brent crude LCOc1, the international benchmark, and further exacerbated the oil-storage problem, as most national strategic reserves and commercial storage facilities were nearing capacity. Furthermore, in April, for the first time on record, West Texas Intermediate (WTI), the US oil benchmark, plunged below zero and into negative price territory.
By the end of April 2020, it had become clear that concerted (or even disconcerted) efforts to negatively affect the US oil price were a losing game for all involved, given the global nature of the economic downturn. Since then, the OPEC+ countries, as well as Brazil, Canada and the United States, have all reduced production and a number have begun purchasing oil from their own strategic reserves in an attempt to take some supply off the market and stabilise prices. Despite these efforts, analysts have observed the seesawing of oil prices and have updated their forecasts to highlight a continued downward trend for oil prices in the foreseeable future. For example, as recently as May 2020, Goldman Sachs was predicting an uptick in prices in 2021 (“Goldman Sachs says it remains bullish on oil prices in 2021”, Oilandgas360.com, 4 May 2020). However, by early June 2020, the company had changed its position and was forecasting a 15–20% correction (“Goldman Sachs says an oil price correction as deep as 20% ‘may already be underway’”, CNBC.com, 9 June 2020). Other global forecasters, including Moody’s, MUFG and Rystad Energy, share a similarly gloomy outlook.
Such volatile and/or depressed oil prices may have a number of serious impacts beyond straightforward profitability concerns. For example, many mineral lease rights are predicated on continuously producing profitability (“production in paying quantities”) based on the idea that, if a company operates at a loss for a lengthy period, it may be unable to maintain its mineral rights.
Survival of the oil and gas industry
Simply put, like any industry, the oil and gas industry requires that the product moves in order for businesses to survive. Barring an unexpected uptick in demand (based in large part on positive trends in the COVID-19 pandemic), oil and gas producers and oilfield service providers will need to find creative ways to remain solvent. As it is, some oil companies are already becoming prime examples of so-called “zombie companies”: companies that have failed for five straight years to make enough money to cover their annual borrowing costs. Similar companies have been abandoned by investors and remain in business – to this point – by tapping banks, bond investors and private equity for additional credit (“Here’s one more economic problem the government’s response to the virus has unleashed: Zombie firms”, WashingtonPost.com, 23 June 2020).
Beyond prices, the downturn has revealed a number of cracks in a highly fragile industry. Cost-cutting and stalled production mean that projects have been abandoned or delayed, employment is down, and facilities may end up being understaffed. Without key technical staff, cybersecurity may suffer, increasing exposure to cyberattacks.
COVID-19 and its Operational Impact
From an operational perspective, COVID-19 has had a particularly deleterious effect on industries and companies that are deemed essential. Such businesses typically do not lend themselves to remote work arrangements and often involve activities that require personnel to be in close personal contact, which clearly increases the risk of COVID-19 transmission. While, at the time of writing, over 100 COVID-19 cases had been confirmed among offshore oilfield workers, the recent spike in cases across the US Gulf Coast indicates increased likelihood that overall case rates across industry employees and contractors will continue to rise.
Essential businesses such as oil and gas companies and oilfield service providers face all the familiar negative effects – layoffs; reduced demand for products and services; applying and qualifying for the Paycheck Protection Program, Small Business Administration, and other government-sponsored emergency relief programmes – while also attempting to meet contractual obligations and regulatory requirements and protect the health of workers. “Social distancing” may adversely affect the effectiveness of safety meetings among oilfield personnel prior to commencing critical operations.
Cold-stacking of vessels, layoffs at – and sidelining of – offshore drilling rigs and refineries, and other short-term responses to the pandemic could have a serious effect in the mid-to-long term. In addition to the above-noted requirements for maintaining lease rights, certain decommissioning activities are accompanied by specific completion deadlines – and failure to meet these deadlines can lead to significant penalties.
COVID-19 has also increased the reporting obligations on oil and gas companies. For example, all vessels calling on US ports are required to report crew and passenger illnesses to the applicable captain of the port (COTP) and the Centers for Disease Control and Prevention (CDC) immediately, or 14 days prior to arriving in a US port. The US Coast Guard has deemed the illness of a person on board a vessel that may adversely affect the safety of the vessel or port facility a “hazardous condition” pursuant to 33 CFR 160.216.
Furthermore, although commercial vessels that have been in certain affected countries are permitted to access the entire United States and conduct normal operations, this is subject to restrictions. Crew members with valid transit or crew member visas must be cleared by Customs and Border Control and the CDC. The CDC has also issued extensive guidance on the supply, use and handling of personal protective equipment (PPE) and other safety equipment.
Companies are also encouraged to explore contractual risk transfer, insurance policies, indemnity agreements, exculpatory/limitation of liability clauses in contracts, and other options as a means to reduce financial risk.
Federal Government Deregulation
Since the early days of his presidential campaign, Donald Trump has made the rollback of environmental regulations a centrepiece of his platform. Following his inauguration in 2017, the Trump Administration has demonstrated support for fossil fuel infrastructure projects and has taken steps to create a permit process with greater regulatory adherence to the original texts of enabling statutes.
President Trump's executive order
Most recently, on 4 June 2020, President Trump signed an executive order directing federal agencies to relax – where lawful under controlling statutory authority – permitting requirements, enforcement activities and compliance deadlines associated with a wide variety of projects, including proposed infrastructure and other major construction projects. In particular, the order instructs agencies to “take all reasonable measures to speed infrastructure investments and to speed other actions in addition to such investments that will strengthen the economy and return Americans to work…”
Although the executive order was issued as a specific response to the economic impacts of the COVID-19 pandemic and relies on the president’s prior declaration of a national emergency, it is in line with the president’s broader efforts to reduce what he perceives as unnecessary regulatory burdens.
In addition to helping clear the path for public and privately held companies, the order allows for the fast-tracking of projects on federal land and civil works and infrastructure projects overseen by the US Army Corps of Engineers and other federal entities. The order also directs agency heads to identify alternative arrangements, exemptions, exclusions, waivers and other actions concerning the application of environmental laws and regulations.
For the Gulf Coast region, the order could have an immediate effect on proposed pipeline, terminal, offshore drilling and other projects that may enable companies to respond to current financial pressures, operational challenges, job losses and changing consumer demand, presuming that legal challenges do not block the administration’s move. Environmental groups, many enabled by substantial funding received following the Deepwater Horizon disaster, have increasingly filed lawsuits seeking injunctions against implementation of the administration’s efforts to reduce regulatory burdens on industry.
Beyond potential environmental and legal issues, some critics of this latest proposed action have also expressed their concern that the order might disproportionately affect minority and economically-at-risk communities, potentially setting the stage for civil rights-based challenges.
Recently, during a review of NEPA, the Trump administration rewrote the rule on how agencies should conduct an environmental review. This was finalised on 15 July 2020, effective in Fall 2020. The administration tweaked some rules with respect to cumulative and indirect effects and environmental trends for reviews to allow for future judicial interpretation. This is a policy shift. There is dispute as to whether these changes are an improvement or whether they will create confusion and become the subject of legal challenges by environmental activists. NEPA has not been updated since 1978.
The National Environmental Policy Act (NEPA)
On the rule-making front, the Council on Environmental Quality has proposed changes to narrow the effect of the National Environmental Policy Act (NEPA) on projects, including limiting cumulative effects, alternatives and speculative global warming issues (85 Fed Reg 1684 (Jan 10, 2020)). Although NEPA in itself does not involve substantive requirements, the NEPA review procedures may add years to the construction schedule of affected projects.
The Outer Continental Shelf Lands Act (OCSLA)
For energy development on the Outer Continental Shelf (OCS), the Bureau of Ocean Energy Management (part of the US Department of Interior) in 2020 finalised new OCS air regulations for fixed structures (85 Fed Reg 34912 (June 5, 2020)). The proposed rule in 2016 from the prior administration greatly expanded air quality reviews authorised by the Outer Continental Shelf Lands Act (OCSLA). The final rule reversed the proposal significantly to adhere to the OCSLA’s authority to consider the impact of offshore emissions on onshore air quality, which mainly resulted in modernisation of the pre-existing OCS air rules. Under the new rule there is still some complexity in reporting air emissions which may impact onshore air quality. In addition, the Department of Interior’s publication of a new offshore Well Control Rule in 2019 remains subject to litigation in federal court.
Work of the Environmental Protection Agency (EPA)
For onshore developments, the Environmental Protection Agency (EPA) has taken several actions to reduce air permit requirements for the oil and gas industry. Under the Trump administration, the EPA has implemented rules that have had the effect of relaxing the requirements used to identify which oil and gas facilities are considered “major sources” for complex air permits, by not automatically aggregating the emissions of all facilities on continuous tracts through their physical alignment (40 CFR 70.2). These facilities now have a quarter-mile leeway; plus, to be considered part of one “source”, the operations (eg, wellheads) must be interconnected. This streamlines air permit requirements by minimising source aggregation and “major source” classification for air permit review.
In 2019, the EPA proposed rules to roll back greenhouse gas methane emissions from leaks in new oil and gas wells, storage and pipelines (84 Fed Reg 50244 (Sept 24, 2019)). The Departments of Interior and Commerce narrowed the consultation requirements for agencies under the Endangered Species Act (50 CFR 402, amended at 84 Fed Reg 45016 (Aug 27, 2019)). Finally, the EPA and Army Corps of Engineers have finalised a new Navigable Water Protection Rule that has narrowed the scope of inland waters (especially wetlands) regulated under the Clean Water Act (85 Fed Reg 22250 (April 21, 2020), already under judicial review in California, Colorado and other federal district courts).
The 2020 US presidential election
To what degree these changes will endure or be reversed in 2021 and beyond depends in large part on the outcome of the 2020 US presidential election. Under a Trump administration, one could reasonably expect to see further action taken to reduce regulatory requirements and oversight of energy projects and operations; under a Biden administration, it is quite possible that the trends of the last three-and-a-half years will be reversed. However, should the COVID-19 pandemic and its negative economic impacts continue for the indefinite future, it is likely that, to a certain degree, the impulse of the occupant of the White House may be a moot point. Facing a down market, low prices and financial distress, it is possible that few oil and gas companies will move forward with significant new investments beyond those required to maintain operations and capacity.
Environmental Protests and Opposition to Energy Infrastructure
Environmental protests are an unavoidable obstacle to any major energy project. Protests through high-profile organisation are frequently well funded, with experienced litigators ready to lead the charge and the support of some of the top universities adding their own funding and expertise to these cases. Plaintiffs and organisers know how to develop the administrative record, organise community resistance and argue in court and before boards.
Recent challenges to fossil fuel and chemical companies have focused on issues such as the disposal and alleged harmfulness of plastics, as well as spills, habitat and wetland preservation, “cancer alleys”, hydraulic fracturing (fracking), endangered and protected species, poly pellets, and social justice and equity.
The Keystone XL Pipeline
Environmental activists, indigenous communities and others have also recently taken aim at pipelines. One of the most prominent, ongoing efforts is against the Keystone XL Pipeline. Individuals and groups opposed to the project have produced legal challenges to an essential environmental construction permit necessary for pipelines and power lines that must cross “waters of the United States”, Nationwide Permit No 12 (NWP 12), issued by the Corps of Engineers and which expedites authorisations for the construction of a variety of utility lines that fall under its purview. In a legal challenge to the Keystone XL pipeline in May 2020, the Sierra Club and others filed a lawsuit in the federal district court in Montana. The district court issued a nationwide injunction (initially applied to all utilities and later narrowed to oil and gas only) and sought vacatur of NWP 12 for the Keystone XL pipeline, based on the Corps of Engineers’ failure to fully consider Endangered Species Act concerns in the issuance of NWP 12 (Northern Plains Resources Group v US Army Corps of Engineers, USDC, D Montana, CV 19-44-GF-BMM, 2020 WL 1875455 (2020), on appeal before the 9th Circuit, Case No 20-35412 et seq).
At the time of writing, the case is pending a filed appeal. The nationwide scope of the Montana court’s ruling means that the case immediately restricts construction of other pending oil and gas pipelines that cross waters of the United States. For instance, the Permian Highway pipeline project is now subject to similar litigation in Texas.
Other pipeline challenges
Other judicial challenges to pipelines, frequently based on NEPA claims, are pending. For instance, the case of Atchafalaya Basinkeeper v US Army Corps of Engineers (894 F 3d 692 (5th Cir 2018)), illustrates the complexity in defending against NEPA challenges. The case involves challenges to the construction of the Bayou Bridge Pipeline, including challenges to the adequacy of an agency environmental assessment, analysis of alternatives, wetland mitigation, climate impacts, and reliance on the agency administrative record and defences of the government. Although challenges may be defeated, they result in years of delay and illustrate how important it is that a permittee should furnish data to the agency to support the administrative record.
What lies ahead
The challenges of 2020 have coalesced to create one of the most challenging periods in the history of most companies. These are, quite frankly, unprecedented times. It’s not without reason, then, that business and legal advisers are exhorting caution.
That said, there is cause for optimism. As localised spikes in economic activity have followed decreased rates of COVID-19, there is clearly significant pent-up demand at every level. While certain industries (such as airlines, hospitality and entertainment) have perhaps moved into the “luxury” category (based simply on consumer fears about congregating in large groups), most industries (such as agriculture, healthcare, manufacturing, food and beverages, and utilities) will continue to provide necessary products and services. All of these industries are fuelled by the oil and gas industry to an important extent.
For those oil and gas companies that can weather this storm, the upcoming year will provide an opportunity to conduct rigorous internal analyses and set the strategy not just for the next year, but well beyond.