In the US, 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 regimes, 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 fugacious nature of hydrocarbons within the reservoir. Nonetheless, private mineral right ownership is the rule rather than the exception in the US, 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 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 are often ordinary people with no industry expertise who 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. It 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 jurisdiction to jurisdiction, 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 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 claim 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 US. 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 US, an oil and gas lessee has an implied right to make reasonable use of the surface to develop and produce oil and gas from the land. 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 any 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 US and has extensive regulations governing the leasing of federal lands, including the payment of royalties, etc. In order to obtain a federal lease, companies execute a lease with the Bureau of Land Management (BLM) requiring the payment of a royalty to the government (equal to one eighth of the value of production), among other things. 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 sophistication when it comes to dealing with oil and gas development. In addition to Native American 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 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 and federal government agencies govern petroleum activities in the US. While historically the US federal government has left regulatory oversight of 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 rapidly 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 following agencies have the express oversight of oil and gas development within their states (although, of note, the level of hydrocarbon production within the states below varies considerably, and states with the lowest levels of oil and gas activity are not included):
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 three 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.
In general, the regulation of oil and gas operations at the local government level is limited, with most states having laws pre-empting municipal, county or parish governments from regulating oil and gas drilling (except with respect to certain zoning laws). 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. It did so by clarifying that local governments have powers to regulate siting, land and surface impacts, and all nuisance-type issues related to the industry, including the ability to inspect facilities and impose fines, and that local regulations enacted pursuant to this new authority may be “more protective or stricter than state requirements.” Nevertheless, many local governments in states with increased hydrocarbon development and limited local authority have utilised their local police power in an effort to regulate oil and gas drilling operations under zoning, land use or nuisance ordinances. Local county and municipal governments have acted to regulate the noise, increased traffic, road disturbances and location issues associated with oil and gas operations. Where local law efforts are disallowed by pre-emption, they may form the basis for later legislative efforts to regulate oil and gas at the state level. Despite state laws that appear to pre-empt most local regulation of oil and gas activity, some local governments have also attempted to impose complete bans on drilling within the applicable county or municipality. These regulatory and legislative developments have often been spurred by alleged incidents of water contamination and other adverse environmental impacts attributed to shale gas development.
There is no national oil or gas company in the US.
A number of laws and regulations affect the oil and gas industry throughout the production cycle (ie, from upstream exploration and production, through to midstream and downstream transportation, processing and refining). As described in 1.2 Regulatory Bodies, above, 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 (and, previously, its predecessor agency, the Federal Power Commission) 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 USD1.27 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 USD13,291 per violation per day for failure to comply with FERC orders, and up to USD1,329 per violation per day for most other violations (all of which are subject to annual adjustment for inflation).
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 United States, 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's Office of Pipeline Safety monitors compliance through field inspections of pipeline facilities and construction projects; inspections of operator management systems, procedures, and processes; and incident investigations. 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 USD250 up to USD50,000 per day per violation. 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 but not limited to 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:
In September 2018, BSEE rolled back several of these provisions, including safety requirements related to reporting failures that have occurred and BSEE-certified inspections. On 2 May 2019, BSEE announced a final rule changing 68 of the 342 provisions in the post-Macondo rule and adding 33 more. Among other things, 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. Laws and regulations protecting the environment have become more stringent over the long term 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 Federal Water Pollution Control Act of 1972 (commonly referred to as the Clean Water Act) prohibits the discharge of pollutants into the navigable waters of the US without a permit. Offshore facilities must also prepare plans addressing spill prevention, control and countermeasures.
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 US. A 'responsible party' could be the owner or operator of a domestic or foreign offshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. 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 US 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.
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 US is one of approximately 170 member countries to 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 US is typically conveyed or governed by an oil and gas lease (whereby an oil and gas exploration company leases minerals from a landowner) 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 from it. 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, 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 this 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. A Pugh 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, on the other hand, 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 intended to provide a high-level review of several key sections in the JOA. Initial indications are that the 2015 AAPL JOA effectively incorporates 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, LLCto 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 from that position as 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/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 no significant 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.
This does not apply in the US.
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 a new well, a revision to a new well (for example, when an operator determines that it is necessary to set a liner deeper in the wellbore due to results from a formation integrity test), a bypass (when an operator drills around a mechanical problem in the original hole to the original target from the existing wellbore), a revision to a bypass, a sidetrack (when the operator drills to a new geologic target or location from an existing wellbore) and a revision to a sidetrack. 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 of many states have special provisions for the taxation of US oil and gas operations, particularly with respect to the treatment of 'intangible drilling and development costs' (IDCs) and 'depletion.'
Intangible drilling costs 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, 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 a one-time binding 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,' on the other hand, 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 required 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.
See 2.5 National Oil or Gas Companies.
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.
There are no other key terms.
This does not apply in the US.
This does not apply in the US.
Under the NGA, interstate natural gas pipelines are subject to a comprehensive federal regulatory regime that is primarily administered by FERC.
Pursuant to Section 3 of the NGA, FERC has authority over the siting, construction and operation of onshore LNG import and export facilities in the US. Similarly, under Section 7 of the NGA, FERC has authority over the siting, construction, operation and abandonment of interstate natural gas pipelines. An applicant seeking to develop an interstate natural gas pipeline must apply for a certificate of public convenience and necessity from FERC under NGA Section 7. Onshore LNG import and export facilities need a FERC order approving the proposed project, but they do not need a certificate of public convenience and necessity unless the project also involves an interstate natural gas pipeline.
FERC’s process for determining whether to issue a certificate of public convenience and necessity involves numerous substantive and procedural requirements, including public notice and comment procedures. In order to streamline the process, FERC has created, and encourages the use of, a pre-filing process that is intended to facilitate proactive engagement between project sponsors and the various agencies, FERC staff, the public and other stakeholders.
In reviewing applications for certificates of public convenience and necessity, FERC balances the project’s public benefits against its potential adverse consequences. FERC first conducts an economic analysis to determine, among other things, whether there is a market need for the project and whether the applicant has attempted to minimise adverse effects on existing customers, pipelines and other stakeholders. If the economic benefits outweigh the adverse economic impacts, FERC will proceed to review the environmental impacts of the proposed project. Accordingly, if an application submitted under Sections 3 or 7 passes FERC’s threshold economic test, FERC will conduct the environmental review process required by NEPA.
Sections 4 and 5 of the NGA give FERC authority over the rates, terms and conditions of service on interstate natural gas pipelines, but they do not confer similar authority over the service offered by LNG import and export facilities. NGA Section 4 requires an interstate pipeline to file tariffs with FERC setting forth the pipeline’s rates, terms and conditions of service. No such rate can take effect without at least 60 days’ notice. During that 60-day period, FERC commences a public notice and comment period. FERC will then review the tariff filing and the public comments to determine whether the filing meets the Section 4 standard that all rates be just and reasonable, and not unduly discriminatory. FERC may either accept or reject the tariff filing, or set it for a trial-type evidentiary hearing before an administrative law judge (ALJ). When setting tariff filings for hearing, FERC may also, and commonly does, assign a separate ALJ to oversee settlement negotiations and provide the parties an opportunity to resolve their disputes without proceeding to costly litigation.
NGA Section 5 provides that FERC may investigate a pipeline’s tariff on its own initiative or upon the filing of a third-party complaint challenging the tariff. If FERC finds that an aspect of the existing tariff is unjust, unreasonable or unduly discriminatory, FERC then has the burden to establish a replacement rate (or term or condition) and explain why it is just and reasonable, and not unduly discriminatory. Alternatively, FERC can deny the complaint or, as with NGA Section 4 proceedings, set the complaint for hearing and/or settlement proceedings before the agency’s ALJs.
Although FERC generally has broad authority over interstate natural gas pipelines, Section 1(c) of the NGA exempts from FERC’s NGA jurisdiction pipelines that are served by interstate pipelines, but satisfy three conditions:
Pipelines that fit this exemption are commonly referred to as 'Hinshaw’ pipelines. A Hinshaw pipeline company may petition FERC for a declaratory order regarding its status as exempt from FERC’s NGA regulation, and it may also apply to FERC for a blanket certificate allowing the pipeline to engage in the sale or transportation of natural gas to the same extent as an interstate pipeline. A pipeline that has obtained such a certificate is subject to FERC’s jurisdiction only to the extent necessary for FERC to enforce the terms of the certificate. Similar regulatory requirements apply to intrastate pipelines that sell or transport gas to an interstate pipeline, or to local distribution companies that take service from interstate pipelines, pursuant to Section 311 of the Natural Gas Policy Act of 1978 (NGPA). These pipelines file rates and charges, as well as a simplified tariff, called a Statement of Operating Conditions, with FERC. Rates for Section 311 service may be approved by FERC or by a state commission.
FERC also has jurisdiction over interstate oil and liquids pipelines under the ICA. However, FERC’s jurisdiction over interstate oil and liquids pipelines is limited to the pipelines’ rates, terms and conditions of service. FERC has no authority over the siting and construction of interstate oil and liquids pipelines.
The ICA requires FERC to determine whether an interstate oil or liquid pipeline’s rates, terms and conditions of service are just and reasonable, and not unduly discriminatory. Unlike the NGA, under which interstate natural gas pipelines are treated as contract carriers, the ICA designates oil and liquids pipelines as 'common carriers' that must provide service to so-called 'walk-up’ shippers. However, over approximately the past decade, FERC has expanded interstate oil pipelines’ ability to provide shippers with firm capacity rights on a contract basis, while still reserving some capacity for walk-up shippers and, thereby, satisfying the statutory obligation to maintain their common carrier status. Rates for many ICA pipelines are set using FERC’s index methodology, which allows for annual changes in a manner that is linked to changes in a US price index and is recalculated by FERC every five years, or they may be established through agreement with shippers or, subject to FERC authorisation, on a market basis. Shippers may challenge an ICA pipeline’s rates through complaints, and FERC may award retroactive damages (called reparations) for excessive charges.
This does not apply in the US.
This does not apply in the US.
This does not apply in the US.
This does not apply in the US.
This does not apply in the US.
This does not apply in the US.
This does not apply in the US.
Under Section 7(h) of the NGA, the holder of a certificate of public convenience and necessity from FERC may exercise the right of eminent domain over the land or other property necessary to construct pipelines and other infrastructure contemplated by the FERC certificate. To exercise that right, the certificate holder must file a condemnation action in the US District Court for the district in which the condemned property is located or in the applicable state’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 does not apply in the US.
This does not apply in the US.
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.
The DWPA requires a streamlined application process, which must be completed within 356 days; however, MARAD can suspend that timeline under certain conditions, if necessary, to gather additional information from the applicant. In reviewing applications, MARAD’s responsibilities include ensuring that the applicant satisfies financial and citizenship criteria, and ultimately granting or denying the licence and issuing the accompanying record of decision. The Coast Guard’s responsibilities include leading the environmental review under NEPA.
Immediately upon receiving a deepwater port application, MARAD and the Coast Guard work with other federal and state agencies to first evaluate whether the application is complete. This initial evaluation process takes 26 days and results in either a Notice of Application published in the Federal Register, or a formal rejection by MARAD.
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.
Along with the NEPA review process, MARAD has its own approval criteria that must be met before a licence may be issued. This includes co-ordination with the Department of Justice and the Federal Trade Commission for review of various other federal laws including antitrust laws which may be impacted by the issuance of a deepwater port licence. MARAD generally implements the suggested requirements of the other federal agencies as additional requirements with which the applicant must comply in order to maintain its licence.
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.
As of 25 June 2019, 26 oil and LNG deepwater port licence applications have been filed with MARAD. The vast majority of the applications have been for LNG import facilities, but the more recent applications have been for oil export facilities. Of the 26 total applications, ten have been approved, five are currently pending, two were disapproved, and nine were withdrawn before MARAD issued a record of decision. Of the ten approved projects, only three are operational. Two of those three are LNG import facilities (GDF Suez-Neptune LNG, and Excelerate Energy-Northeast Gateway) and one (Louisiana Offshore Oil Port) is a bi-directional oil facility. Seven of the ten approved projects either surrendered their licence, decommissioned the facility, or withdrew their applications after MARAD’s record of decision, but before MARAD issued the licence. One of the approved projects is an LNG export facility (Delfin LNG) for which MARAD has issued a favourable record of decision but has not yet issued the licence. All five of the currently-pending applications are for oil export facilities.
This does not apply in the US.
In accordance with federal law and as described above, a foreign business must create one or more wholly-owned US entities through which it may acquire the leasehold interests in order to hold an oil and gas interest in a federal lease. However, there is no single, federal system in the US governing the formation of such entities, and any new entity(ies) will be formed in and administered subject to the laws of a particular state. The state of formation may be the state where the property is owned or business is conducted, 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 president of the US 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 US. 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.
As described above, 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 September 2018, the EPA issued a proposal to roll back parts of the 2016 performance standards, including with respect to fugitive emissions, pneumatic pumps, and other operational and administrative requirements. 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, the BLM finalised a suspension of certain requirements until 2019 and, in February 2018, published a proposal to revise or rescind the rules. 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. In addition, in May 2016, the EPA finalised rules regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements.
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).
This does not apply in the US.
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 US 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. As previously noted, although the rules remain in effect, the EPA has issued a proposal to roll back parts of the 2016 performance standards, including with respect to fugitive emissions, pneumatic pumps, and other operational and administrative requirements. 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.
Pennsylvania has enacted new permit requirements, effective from August 2018, for new or updated well sites that require the use of certain equipment to reduce methane emissions. The new requirements also set thresholds on volatile organic compounds, hazardous air pollutants and nitrogen oxides.
Ohio has established robust leak detection and repair requirements to curtail fugitive emissions through its General Permit programme for natural gas wells and compressor stations.
Colorado has enacted rules that prohibit unnecessary or excessive venting and flaring, and require that operators notify the local emergency dispatch or designee of any flaring, except in certain circumstances.
North Dakota requires operators to submit gas capture plans and capture at least 85% of gas produced.
California has enacted additional requirements for reducing methane emissions, including quarterly monitoring requirements of methane emissions from oil and gas wells and other processing and delivery equipment.
Other hydrocarbon-producing states, such as New Mexico, 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. In three opinions issued in 2016 – Sierra Club v FERC (Freeport), Sierra Club v FERC (Sabine Pass), and EarthReports, Inc et al v FERC – the DC Circuit explained that, although FERC has authority to review the direct greenhouse gas emissions associated with an LNG facility and related midstream facilities, the DOE has the authority to analyse the greenhouse gas emissions associated with the export of LNG. As a result, FERC’s NEPA obligations with respect to LNG facilities are more constrained than its NEPA obligations for interstate natural gas pipelines, because FERC need not consider the downstream, indirect impacts of an LNG facility and related midstream assets.
Climate change-related NEPA obligations are similarly impacting 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.
This does not apply in the US.
This does not apply in the US.
The US has become a major LNG exporter in recent years. According to the US Energy Information Administration (EIA), in 2017 the US exported more natural gas than it imported for the first time since 1957. The EIA reports that the US repeated that natural gas net-export trade balance again in 2018, with US LNG exports reaching a record high of approximately 1,083 Bcf delivered to 37 countries. In addition, in December 2018 the EIA reported that it expects US LNG exports to continue to increase, as US LNG export capacity is anticipated to double by the end of 2019.
Companies seeking to import or export natural gas to or from the US, via an onshore facility, are required by the NGA to obtain authorisation from FERC and the Department of Energy’s Office of Fossil Energy (DOE/FE). However, as discussed above in 3.12 Laws and Regulations Governing Exports, the regulatory requirements are different for offshore LNG facilities.
Pursuant to Sections 3(a) and 3(c) of the NGA, FERC authorises the siting, construction and operation of onshore LNG import and export facilities in the US. 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 30 months. However, as noted below, in Section [6.X], 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 US. The DOE/FE evaluates applications to import or export to or from countries with which the US 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 US 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.
As of 17 May 2019, according to the FERC website, there are four existing LNG export projects (Dominion-Cove Point LNG; Cheniere/Sabine Pass LNG – Trains 1–5; Cheniere – Corpus Christi LNG Train 1; and ConocoPhilips in Kenai, Alaska); seven export projects with both FERC and DOE non-FTA approvals under construction (Sempra-Cameron LNG; Freeport LNG Dev/Freeport LNG Expansion/FLNG Liquefaction; Cheniere – Corpus Christi LNG; Sabine Pass Liquefaction; Venture Global Calcasieu Pass; ExxonMobil -– Golden Pass; and Southern LNG Company in Elba Island, Georgia); six export projects with FERC and DOE non-FTA approvals that are not under construction (Southern Union-Lake Charles LNG; Magnolia LNG; Sempra Cameron LNG; Port Arthur LNG; Driftwood LNG; and Freeport LNG Dev); and 14 other LNG export projects that are pending FERC and/or DOE non-FTA approvals or that are in FERC’s pre-filing process (including Gulf LNG Liquefaction; Texas LNG Brownsville; and Venture Global LNG). There are no pending applications for LNG import projects.
LNG facilities must also obtain various other permits and approvals, including water- and air-related permits, from federal and state regulatory agencies.
There are no other unique or interesting aspects of the petroleum industry in the US worthy of mention.
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 30 September 2015, Sabine moved to reject certain gathering and processing agreements with its midstream counterparties. In each of the agreements, Sabine had agreed to 'dedicate' its leasehold interest in certain leases to the performance of the agreement. Moreover, each agreement expressly recited the parties’ intention that the obligations contained therein were covenants running with the land. Despite these provisions, 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.
Among other things, 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.
The Sabinedecision provides three principal factors to consider when assessing how courts may analyse the rejection of a midstream agreement:
BOEM Sole Liability Guidelines
In September 2015, the BOEM issued draft guidelines describing revised procedures and criteria that it intends to implement when determining an energy company’s financial ability to carry out its offshore obligations – namely, decommissioning obligations for wells, platforms, pipelines and other facilities located in the Outer Continental Shelf (New Guidelines). The New Guidelines replace the BOEM’s existing 2008 Notice to Lessees (2008 NTL), which sets forth the general criteria for determining a company’s financial ability to fulfil decommissioning obligations. Note that 'decommissioning obligations' are based on the BOEM’s estimate for plugging and abandonment liability associated with particular assets, which is not expected to change based on the New Guidelines.
Notably, the general criteria set forth in the 2008 NTL remain unchanged under the New Guidelines – the BOEM continues to look at the following five factors for determining whether a company is required to post financial assurance or supplemental bonding (and, if so, to what extent and in what manner they are required to do so):
Based on these criteria, the BOEM will develop a 'tailored programme' of financial assurance requirements for each specific company.
A key change under the New Guidelines is that companies are no longer 'waived' or exempt from posting financial assurances. The 2008 NTL allowed larger companies to rely on their size and net worth, and essentially 'self-insure' against future decommissioning liabilities by setting aside funds on the company’s balance sheet as opposed to maintaining supplemental bonds/securities. Under the New Guidelines, waivers are no longer granted and eligible lessees are limited in their ability to self-insure (ie, limited to a maximum of 10% of their tangible net worth – total assets less total liabilities and intangible assets). Thus, many large independents would be limited under the New Guidelines in their ability to self-insure. Although the full interpretation by the BOEM remains to be seen, the BOEM will likely provide such companies with a credit of up to 10% of their tangible net worth; however, decommissioning obligations above that line of credit will require additional forms of financial assurance. Mid-size and smaller independents that currently do not self-insure are not likely to be materially affected by the New Guidelines, and will continue to rely exclusively on forms of security.
In July 2016, after months of careful consideration and industry engagement, the BOEM issued the New Guidelines. In December 2016, it issued Orders to Provide Additional Security for sole liability properties (ie, leases, rights-of-way, or rights-of-use and easements for which the holder is the only liable party). On 6 January 2017, the BOEM announced that it was extending the implementation timeline for the New Guidelines by six months, and on 17 February 2017, it announced that it was withdrawing the New Guidelines for six months to allow time for the Trump administration to review the complex financial assurance programme. On 22 June 2017, the BOEM announced that it was further extending the review period for an unspecified amount of time in order to allow adequate time to prepare a report recommending options for revising or rescinding the New Guidelines. During the review period, implementation issues associated with the New Guidelines will be discussed; however, the BOEM may re-issue sole liability orders before the end of the review period if it determines there is a substantial risk of non-performance.
Colorado Senate Bill 19-181
On 3 April 2019, the Colorado Legislature passed Senate Bill 19-181, which 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.
Senate Bill 19-181 also elevates health, safety and environmental considerations to a position of prominence in permitting decisions. To this end, the COGCC’s new mission is to regulate industry activities so as to protect these values rather than to foster resource development, while also considering effects to health and the environment. To facilitate and reflect this shift in priorities, the bill professionalises the COGCC and changes its makeup. Specifically, the bill makes membership a full-time, paid position subject to appointment by the governor and confirmation by the senate; it reduces the number of members who must have experience in the oil and gas industry from three to one; and adds members with experience in land use or planning, public health, and an ability to contribute to and aid the COGCC in making sound, balanced decisions. Senate Bill 19-181 also requires the COGCC and Air Quality Commission to undertake to make a number of rules relevant to these issues.
Finally, Senate Bill 19-181 alters pooling, drilling and permitting requirements. In addition to requiring operators to seek local government approval before applying for state permits from the COGCC, the bill changes the number of mineral-interest owners who must consent before an operator can apply for a COGCC pooling order from just one to 45% of the owners to be pooled. It also bars operators from using the surface owned by a non-consenting owner without their permission, and slightly increases the royalty rate for non-consenting owners during the payback period. In addition, the bill requires every operator to provide assurance that it is financially capable of fulfilling every obligation imposed by all current and future COGCC rules, and removes caps on fees that operators must pay when seeking a permit.
The practical effect of Senate Bill 19-181 in Colorado remains to be seen. Colorado is the seventh-largest producer of oil and sixth-largest producer of natural gas in the United States. However, the majority of the development within the state has taken place within jurisdictions that rely on and are, therefore, friendly to industry.
In addition, while no other hydrocarbon-producing states have proposed such robust reform for regulation of oil and gas activities as Colorado, the recent Colorado updates could be indicative of a trend towards increased regulation where political climates so permit. For example, New Mexico has recently signalled interest in enhancing the state’s regulatory authority over oil and gas operators, including with respect to control of methane emissions, enforcement capabilities and revenue generation through royalty rates on state lands.
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 conducing NEPA analyses.
The CEQ guidance document includes the following proposals:
Federal Tax Laws and Court Decisions Drive FERC Pipeline Rate Actions
Since early 2018, FERC has proposed and implemented several significant changes to jurisdictional oil and gas pipeline rates. These changes arose in response to:
On 15 March 2018, FERC addressed these developments in a series of actions. FERC issued its Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) stating, in response to United Airlines v FERC, that it will no longer permit pipelines organised as MLPs to recover a separate income tax allowance in cost-of-service rates. For oil pipelines, FERC stated that it would address the effect of the Revised Policy Statement, along with the effects of the Tax Cuts and Jobs Act, in the next five-year update of the oil pipeline index, which will occur in 2020. FERC required oil pipelines to immediately change cost-of-service reporting in order to collect information on the effect of income-tax allowances. For natural-gas pipelines, FERC issued a proposed rule that would apply the Revised Policy Statement and income tax rate reduction by first requiring a one-time informational filing. If the filing showed that a pipeline was over-recovering its costs, then the pipeline could choose to take action to reduce its rates, justify its rates, or do nothing, but with the threat of subsequent FERC investigation. FERC also issued a Notice of Inquiry requesting comments on the effect of the Tax Cuts and Jobs Act on FERC-jurisdictional rates, and particularly with regard to its impact on accumulated deferred income taxes and bonus depreciation.
On 18 July 2018, FERC affirmed the Revised Policy Statement in response to challenges on rehearing. On the same day, FERC adopted a final rule for natural-gas pipeline rates that was substantially the same as the proposed rule. FERC has yet to take action on the Notice of Inquiry.
Taken together, changes in income tax allowance policy and reductions in corporate income tax rates have had significant effects on the attractiveness of the MLP structure in the US midstream industry. This past year has seen a wave of conversions and mergers in which a significant number of MLPs that hold FERC-jurisdictional assets converted to corporations or merged with and into parent corporations.
DOE Revises LNG Export Destination Reporting Policy
On 19 December 2018, the DOE determined that it would no longer require holders of LNG and natural gas export authorisations to report the country (or countries) into which exported LNG or natural gas was “received for end use,” and would instead require only that authorisation-holders report the country or countries into which LNG or natural gas “was actually delivered.” In doing so, the DOE reversed a policy that had been in place since February 2016 and had been derided by some in the LNG industry as difficult, if not impossible, to comply with fully. The DOE issued a policy statement setting forth its intentions to apply the policy to future authorisations, while also issuing a blanket order to modify the approximately 40 authorisations that the DOE had issued between February 2016 and December 2018 with the “received for end use” language.
Trends and Developments: Gulf Coast Energy Export Facilities
Energy companies in the Gulf Coast region of the United States have seen a marked uptick in production and export activity over the past several years — to such an extent that the word 'uptick' is no longer a sufficient descriptor. 'Leap' is a more accurate term for the rapidly expanding demand for US petroleum products and the concomitant increase in infrastructure projects intended to meet and capitalise on this demand.
Examples of this growth abound: In February 2019, ExxonMobil announced that it would be investing USD10 billion in US Gulf Coast energy infrastructure. In May 2019, S&P Global Platts reported that the United States now exports more than three times as much crude oil and LNG as it did when Hurricane Harvey struck the Houston region in August 2017 — an all-time high, according to RBN Energy. In early June 2019, a record number of Very Large Crude Carriers (VLCCs) was scheduled to load medium-sour crudes from the Louisiana Offshore Oil Port destined for overseas markets. At the same time, Sentinel Midstream announced that it had submitted licence applications with the US Maritime Administration (MARAD) to construct and operate a deep-water crude export facility off the coast of Freeport, Texas, that would be capable of fully loading VLCCs. In mid-June 2019, Phillips 66 announced the construction of two new crude oil pipelines: the 24-inch, USD1.6 billion Liberty Pipeline running from the Rockies and Bakken production areas to Cushing, Oklahoma, and a 30-inch, USD2.5 billion pipeline system that will move product from Cushing to destinations on the Texas Gulf Coast.
Among the firm's clients, there has likewise been a heightened focus on energy infrastructure development. In recent months, companies have sought broad-ranging advice on agreements related to 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 current trend has been driven by a number of interrelated factors, including increased production in the Permian Basin, Rockies, Bakken and other production areas in the western and mid-continental United States; lower global crude prices; US sanctions on key petroleum-producing countries (including Venezuela and Iran); production cuts by the Organization of Petroleum Exporting Countries (OPEC); and increased demand from Asian oil buyers.
Clearly, momentum is on the side of the Gulf Coast energy industry. To flip the old saying on its head, however, every silver lining has a cloud. Take technology, for example: the very same unmanned aerial vehicle (UAV, or drone) capabilities that allow pipeline companies to survey and monitor thousands of miles of infrastructure corridors are now being used by environmental and activist groups to patrol contested facilities and document protest activities.
In the press to launch new projects and expand export capabilities to meet growing demand, oil and gas and oilfield service companies with operations in the Gulf Coast and beyond must also address a number of critical challenges. These include the potential impacts of trade wars and catastrophic weather events on infrastructure costs; local zoning requirements; state law-driven mineral rights issues; and a range of environmental and regulatory concerns.
Trade Wars and Hurricanes: Man-made and Natural Events Leading to Higher Costs
As the US energy industry is heating up, relationships between the United States and several of its key trading partners are cooling down. While tit-for-tat tariffs between China and the United States may shrink demand for US LNG in the massive Chinese market, such actions would likely also increase the price of steel, significantly raising the overall cost of building new pipelines, as well as production and export facilities. If such trade wars drag on, they could trigger global or regional recessions that would result in falling demand for energy.
Trade disputes aren’t the only storms on the horizon. As recent history has demonstrated, the Gulf Coast is vulnerable to severe weather, from tornado outbreaks to massive hurricanes coming in from the Atlantic Ocean. As US exporters increase their share of global energy flow, the potential cost of a destructive weather event — from infrastructure and facility damage to port closures and power outages — also grows. Investors and oil and gas companies must take into account these weather-related risks when planning new facilities and developing disaster-recovery strategies.
One factor weighing in oil and gas companies’ favour has been the Trump administration’s recent, expressed willingness, in times of catastrophe, to waive the Jones Act, which forbids the use of non-US vessels to deliver goods between US ports. For a brief period following the destruction of Puerto Rico by Hurricane Maria in September 2017, the administration allowed non-US ships to carry food, fuel and supplies to the island. Should a similar, large-scale disaster strike the Gulf Coast energy industry, it is possible that such an exception might also be made.
Zoning: Can You Really Do That on Your Land?
Before undertaking any major development activity or infrastructure project, oil and gas and pipeline companies must understand a number of important issues, including the zoning of such land and the surface and mineral rights associated with land that is owned or leased.
Zoning is a powerful tool that local governments wield to promote certain interests and achieve specific goals. The ways in which land can and cannot be used have a significant impact on economic development, tax revenues, and quality of life, among other areas, as well as a direct effect on corporate returns on investment. If the land leased or purchased is not zoned in accordance with the intended purpose, the interested party will be required to either abandon the project or pursue a public process to rezone the property or obtain an exception, which can result in significant project delays, lead to negative public relations and press coverage, increase project financing costs, and set the stage for extended litigation.
Mineral Rights: Who Holds the Power?
While the identification of zoning and land-use issues requires a certain level of due diligence, potential conflicts involving surface and mineral rights can be much less apparent —at least initially. Companies and their legal counsel must conduct appropriate title searches and establish and understand any servitudes, easements, public rights of way, and other surface-use agreements that could create barriers to land development and infrastructure projects.
Ownership of mineral rights is a key issue that may create conflicts between parties. This is particularly true in today’s environment, as horizontal drilling and similar technologies have allowed for oil and natural gas exploration that is initiated some distance from the land below which the resources themselves are found.
Complicating the establishment of these mineral rights and the resolution of potential conflicts is the mosaic of state laws governing these agreements and ownership of property. In Texas, for example, fee simple ownership of land includes the surface as well as the air above and minerals below, unless such rights are severed from the surface estate. Where such rights have been severed, 'oil is king' — in other words, minerals (and mineral rights) are dominant and the surface estate exists for the 'reasonably necessary use' of the mineral owner. Without adequate surface waivers, for example, a mineral owner could require that a solar power developer (and surface owner) move its solar panels to accommodate drilling and production of oil and gas.
In Texas, mineral estates can be permanent, but mineral leasehold estates (under which many oil and gas leases are provided) are generally granted for a two to three-year period, after which the lease remains in force only as long as the resources are produced in paying quantities.
Louisiana also follows a fee simple ownership model, in which the surface rights and rights to everything above and below the surface are held by the property owner unless such mineral rights have been reserved by a previous owner or have been transferred – in either case creating a 'mineral servitude.' Unlike other states, which allow for a mineral estate that can be severed from the surface estate, mineral rights in Louisiana are separated from the surface rights through the creation of a mineral servitude interest, which remains in place as long as it is being used, but reverts to the current landowner after ten years of non-use. Mineral rights do not dominate; unless otherwise agreed, both the mineral owners and the surface owners have equal right to use the surface of the property for their respective activities with due regard for the other’s rights.
Furthermore, as of 1921, any land sold by the State of Louisiana does not include mineral rights, and such mineral interests will belong to the state forever, even if the state sells the property and fails to reserve the minerals. Louisiana also follows an '80% rule' in which co-owners of land may not conduct operations on the land, nor may leaseholders engage in surveys or other activities, without the express permission of co-owners owning at least an undivided 80% of the land. Co-owners of such servitudes who do not agree to such operations are not held liable for the cost of development and operations on the land, except out of the co-owners’ share of production.
Other Gulf Coast-region states, including Alabama, Mississippi and Georgia, have their own laws and exceptions governing surface and mineral rights, including expiration of rights following periods of non-use. Site acquisition structures, including lease and fee structures, are also strictly defined and differ across jurisdictions.
With this in mind, energy companies seeking to acquire real property or participate in infrastructure development projects must ensure that they have conducted full due diligence with respect to the ownership of surface and mineral rights and the various state laws that may affect activities governed by these rights. Contracts with landowners, leaseholders and other parties must clearly spell out these rights and establish mechanisms for resolving potential disputes.
Under these conditions, obtaining appropriate title insurance is a baseline requirement before initiating any project. At its most fundamental, title insurance ensures that if the state of the title is other than as represented on the face of the policy, and if the insured suffers losses caused by recorded and unrecorded defects as a result of the difference, the insurer will reimburse the insured for that loss and any related legal expenses, up to the face amount of the policy. Title insurance does not guarantee the state of the title; rather, it represents an agreement to defend and indemnify the insured.
Insurance coverage is also available, in the form of endorsements, for minerals and other subsurface substances, access and entry, encroachments, restrictions, loss and damage to surface improvements through mineral development, and other issues. Responding to emerging technologies, these policies may include language relating to hydraulic fracturing, solar energy generation, and other activities associated with the development and production of energy from traditional and renewable sources.
Understanding and managing these complex mineral rights issues and title insurance coverage regimes can be a challenge for any company. For non-US businesses, including an increasing number of companies and investors from Asia, it can be even more difficult to pinpoint issues that may negatively affect project progress. With this in mind, businesses should ensure that they are working with local counsel with firsthand experience and proven, co-operative relationships with government agencies and officials in the jurisdictions in which they plan to operate.
As demand for US oil and gas has risen sharply, companies are acting quickly to take advantage of these new opportunities to expand total energy exports and market share. Fast action, however, should not preclude the issues surrounding exploration, production and export of these products. US and non-US companies operating in this sector must take reasonable steps to ensure that they are identifying local, state and federal laws that can affect their investments, and that they negotiate contract terms that protect their interests most effectively.
The bottom line? The Gulf Coast petroleum industry can and will grow quickly — but it must also grow intelligently.