In the USA, mineral rights are predominantly owned by private citizens or companies, rather than the state or federal government.
Private mineral ownership is based on the principle that the owner of real property owns everything both above and below the surface, including the minerals. US common law has modified this principle to address the existing nature of hydrocarbons within the reservoir.
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 rights to the minerals or to the subsurface. In turn, the mineral rights can be separated into undivided shares, or the "minerals" can be divided into rights for the oil and natural gas, water and/or other named minerals or resources (eg, sulphur, helium, etc).
In areas with significant historical production, there may be dozens of mineral owners with rights underlying a single tract, with the surface owner having no right to the produced minerals. These circumstances can generate complex title issues that must be understood by mineral interest owners and exploration and production companies leasing and drilling such interests.
The oil and gas "lease" is more of a hybrid of a deed and contract than a traditional real estate lease. The lease typically conveys oil, gas and certain mineral rights in the leasehold lands to the lessee, who accepts those rights in exchange for payment to the lessor of a share of production (or the proceeds therefrom).
The majority of modern oil and gas leases grant the lessee the right – but not the obligation – to develop the minerals during the initial term of the lease. The nature of the property interests conveyed by the lease varies from state to state, and may be further defined according to the terms of individual leases.
Typically, states follow one of two theories of hydrocarbon ownership: ownership-in-place or the exclusive right-to-take. Under the ownership-in-place theory adopted by courts in many hydrocarbon-producing states (including Texas), the landowner or mineral owner owns a real property interest in all substances lying within the owned land, including oil and gas.
The landowner’s ownership interest is qualified, in the case of oil and gas, by the operation of the rule of capture, whereby the owner of a tract of land acquires title to the oil and gas produced from wells drilled on his or her land, even if the oil and gas migrated from neighbouring tracts. Thus, subject to trespass, the ownership in the substances is lost if the oil and gas underlying a tract of land migrates from beneath that tract.
However, the rule of capture is not an absolute rule and has been altered in many hydrocarbon-producing states to promote more ordered production. For example, gas that has already been extracted from the land and injected into underground storage is no longer subject to the rule of capture and remains the property of the person who originally captured the gas.
Furthermore, many states have adopted the doctrine of correlative rights. This doctrine limits the rule of capture when the extraction or removal of hydrocarbons is completed negligently or in a manner that causes waste. In that case, the mineral owner may be entitled to recover damages from the operator that negligently or wastefully extracted the hydrocarbons.
Other states, such as Oklahoma, follow the exclusive right-to-take theory of ownership, under which the landowner does not own hydrocarbons beneath the owned land and, instead, merely has the exclusive right to capture the substances by conducting operations on the land. Once reduced to dominion and control, the substances become the object of absolute ownership but, until capture, the property right is described as an exclusive right to capture.
The two theories of ownership have wide-ranging effects on the oil and gas industry, which have been examined by a host of professionals during the more recent wave of energy restructurings in the USA. In states that follow the ownership-in-place theory, a lessee’s interest in an oil and gas lease is viewed as a fee simple determinable estate in the oil and gas in place. In states that follow the exclusive right-to-take theory, courts typically characterise the lessee’s interest as an irrevocable licence or a profit à prendre.
In the USA, an oil and gas lessee has an implied right to make reasonable use of the surface to develop and produce oil and gas from the land. This is particularly important given the frequency with which the mineral estate is severed from the surface estate. By classifying the mineral estate as the "dominant estate", the lessee is assured that a surface estate owner cannot prevent reasonable development activities, thereby rendering the mineral estate worthless. Nevertheless, conflicts between surface owners and mineral owners or lessees are frequent, and many lessees and surface owners execute surface use agreements in advance of significant development of the mineral estate or provide for specified restrictions within the lease itself.
While private mineral ownership dominates in the majority of hydrocarbon-producing US states, the federal, tribal and most state governments own property which they may lease for oil and gas development. The federal government owns about 30% of all onshore lands located in the USA and has extensive regulations governing the leasing of federal lands, including the payment of royalties, etc. In order to obtain a federal lease, companies execute a lease with the Bureau of Land Management (BLM) requiring the payment of a royalty to the government. Tribal regulation varies considerably across tribes, and the tribes have varying degrees of technical capacity with respect to oil and gas development, which is partly the justification for the Bureau of Indian Affairs to have concurrent jurisdiction over certain tribal issues.
This structure of dual regulation can cause extended delays in obtaining approval to assign tribal leases and/or obtain drilling permits on tribal lands. Thus, operations on tribal land can be complex, and tribal land ownership adds regulatory hurdles to a company’s oil and gas operations.
Domestic onshore oil and gas development is regulated primarily by the applicable state where oil and gas operations occur, but a variety of state, federal and tribal government agencies govern petroleum development activities in the USA.
While historically the US federal government has left regulatory oversight of onshore oil and gas exploration and production activities to state governments, public concern and media scrutiny about oil and gas operations have increased as hydrocarbon development continues to expand into more urban areas. In response, regulators and legislators at both the federal and state levels have taken steps to increase regulations and enhance enforcement against oil and gas operators in order to protect public safety and natural resources.
At the state level, numerous agencies have the express oversight of oil and gas development within their states (although, of note, the level of hydrocarbon production within the states varies considerably). At the federal level, the following agencies have primary responsibility for governing oil and gas operations:
At both state and federal levels, recent regulatory initiatives have primarily focused on four key issues related to shale gas development:
At the state level, a number of the traditional hydrocarbon-producing states have revised existing regulations to include heightened well-drilling and installation standards, waste fluid management requirements and varying disclosure requirements.
In general, the regulation of oil and gas operations at the local government level is limited, with most states having laws that pre-empt municipal, county, borough, or parish governments from regulating oil and gas drilling (except with respect to certain zoning laws). One notable exception is Colorado, which, in 2019, placed regulation of the surface impacts of oil and gas exploration in the control of local communities, as co-equals with the state.
There is no national oil or gas company in the USA.
A number of laws and regulations affect the oil and gas industry throughout the production cycle (ie, from upstream exploration and production, through to midstream and downstream transportation, processing and refining). As described in 1.2 Regulatory Bodies, the system of laws and regulations affecting oil and gas operations varies depending on the state where operations are conducted and/or whether operations are conducted on privately owned or government-owned properties. What follows is a high-level review of major US laws and regulations affecting the upstream industry.
The development of oil and gas on federal properties starts with leasing programmes that are governed primarily by the Mineral Leasing Acts of 1920 and 1947. The Mineral Leasing Act of 1920 opened federal lands to hydrocarbon development and initially offered the oil and gas operator/lessee an exclusive two-year prospecting permit covering 2,560 acres of unproved land. The lessee was required to begin drilling operations within six months, and to drill wells to an aggregate depth of 2,000 feet within two years. Upon the discovery of oil or gas in paying quantities, the lessee was entitled to a 20-year lease of one-quarter of the land, at a royalty of 5% and an annual rental of USD1 per acre.
Because of concerns about physical and economic waste under a system of unfettered rule of capture, legislators passed amendments to the Mineral Leasing Act, culminating in the Mineral Leasing Act of 1947. One such important amendment was enacted in 1935 when the principle of compulsory unitisation was granted to the Department of the Interior, to cause lessees to enter into a co-operative unit plan of production to lease and develop a specified federal area. Similar to forced pooling (whereby an operator is permitted to "pool" other mineral interest and working interest owners to produce a unit), compulsory unitisation allows the federal government to force interest owners to effectuate a common unit development plan.
Congress also amended the terms of federal leases in 1946 to encourage additional exploration and development by providing for a flat 12.5% royalty on non-competitive leases and reducing the term of competitive leases from ten to five years. Finally, the Mineral Leasing Act of 1947 added an additional 150 million acres of federal lands to the public domain, and generally affirmed the amendments to the Mineral Leasing Act of 1920, other than providing that all proceeds generated from federal hydrocarbon development be directed to the federal, rather than state, treasuries.
Congress also enacted legislation governing midstream activities, including natural gas and oil pipeline transportation. The NGA gives FERC regulatory authority over various aspects of natural gas transportation. Specifically, FERC has jurisdiction over the siting, construction and operation of onshore LNG import and export facilities, pursuant to NGA Section 3, and interstate natural gas pipelines (including interstate storage facilities), pursuant to NGA Section 7. Such facilities may not be constructed or operated without a FERC-issued certificate of public convenience and necessity.
Further, Sections 4 and 5 of the NGA give FERC jurisdiction over the rates, terms and conditions of service on interstate natural gas pipelines and storage facilities, which authority does not, however, extend to LNG import and export facilities. Under the ICA, FERC has similar authority over the rates, terms and conditions of service on interstate oil and liquids pipelines. However, unlike interstate natural gas pipelines and onshore LNG import and export facilities, FERC has no jurisdiction over the siting, construction and operation of interstate oil and liquids pipelines.
FERC has broad enforcement authority under the NGA and the Natural Gas Policy Act of 1978 (NGPA), including the ability to levy civil penalties for rule violations or market manipulation of up to approximately USD1.31 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 USD13,685 per violation per day for failure to comply with FERC orders, and up to USD1,368 per violation per day for most other violations (all of which are subject to annual adjustment for inflation).
Natural gas deepwater ports – but not oil deepwater ports – must secure approval from the Department of Energy’s Office of Fossil Energy (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 safety of interstate natural gas pipelines, oil pipelines and LNG facilities falls under PHMSA’s jurisdiction. PHMSA's primary mission is to regulate the transportation of hazardous materials and to protect people and the environment from the risks inherent in the transportation of hazardous materials by pipelines and other modes. PHMSA has developed regulations and standards for the handling and safe transport of hazardous materials in the USA, and to ensure safety in the design, construction, operation, maintenance and spill response planning of approximately 2.6 million miles of natural gas and hazardous liquid transportation pipelines.
PHMSA's inspection and enforcement staff promulgates the agency’s safety and training standards and ensures that the entities under its jurisdiction comply with the pipeline and hazardous materials safety regulations. PHMSA’s jurisdiction extends beyond pipelines transporting hazardous materials, to include entities that manufacture, re-qualify, rebuild, repair, recondition or retest packaging (other than cargo tanks and tank cars) used to transport hazardous materials.
PHMSA has a full range of enforcement tools to ensure that the hazardous material transportation industry takes appropriate and timely corrective actions for violations, responds appropriately to incidents, and takes preventative measures to preclude future failures or non-compliant operation. Violations of PHMSA’s regulations can lead to both civil and criminal enforcement proceedings in addition to fines ranging from USD508 (for training violations) up to USD225,134 (for pipeline safety violations) per day per violation, and USD2,251,334 for a related series of violations.
Federal oil and gas development is also subject to the National Environmental Policy Act (NEPA), which was one of the first laws to establish a broad national framework for protecting the environment. The basic policy underlying NEPA is to ensure that all branches of government give proper consideration to environmental impact prior to undertaking any major federal action that has the potential to significantly affect the environment.
NEPA requires each federal agency to prepare an Environmental Impact Statement (EIS) before taking any federal action that could significantly affect the quality of the human environment, subject to certain exclusions and exemptions. When preparing the EIS, the agency is required to evaluate alternatives to the proposed action and the direct, indirect and cumulative environmental impacts of both the proposed action and any such alternatives. The requirements of NEPA may result in increased costs, delays and the imposition of restrictions or obligations on an oil and gas company’s activities, including the restricting or prohibiting of drilling.
Offshore operations are governed by an additional set of complex regulations reflecting the ecological sensitivity of the shorelines and shallow-water areas of the US Gulf of Mexico (GOM), as well as the additional technical complexity of offshore production.
The US Oil Pollution Act of 1990 (OPA) and related regulations impose a variety of requirements on "responsible parties” related to the prevention and/or reporting of oil spills and liability for damages resulting from such spills in US coastal waters and foreign spills reaching the USA. A "responsible party" could be the owner or operator of a domestic or foreign offshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs, alongside a variety of public and private damages. Moreover, a party cannot take advantage of liability limits if the spill was caused by gross negligence or wilful misconduct, or if it resulted from violation of a federal safety, construction or operating regulation.
The US Outer Continental Shelf Lands Act (OCSLA) extends US jurisdiction to the subsoil and seabed of the OCS, and authorises regulations relating to safety and environmental protection applicable to lessees and permittees operating in the GOM. Under OCSLA, the USA has enacted regulations that require operators to prepare spill contingency plans and establish air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulphur dioxide, carbon monoxide and nitrogen oxides. Violations of lease conditions or regulations related to the environment issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and cancelling leases.
OCSLA also provides for regulation of pipelines on the OCS, which is characterised as an exclusively federal domain separate from any US state. Transportation of oil or gas by pipeline across or within the OCS is therefore not "interstate" in character and correspondingly not subject to regulation under the NGA (for natural gas) or ICA (for petroleum liquids). Pursuant to Section 5 of OCSLA, OCS pipeline rights-of-way are managed by the BSEE and are subject to open and non-discriminatory access requirements. While FERC has very limited authority over OCS pipelines, it may exercise NGA authority over natural gas pipelines that cross from the OCS into state waters, and ICA authority over movements of petroleum liquids from the OCS into state waters.
BSEE provides for complaint-based enforcement of OCSLA’s open-access requirements. Remedies for a pipeline’s failure to provide open and non-discriminatory access include orders to provide such access, civil penalties of up to USD10,000 per day, referral for civil action by the US Department of Justice, and the initiation of a proceeding to forfeit the relevant OCS rights-of-way.
Laws and regulations protecting the environment have generally become more stringent and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault. For example, the US Comprehensive Environmental Response, Compensation and Liability Act (commonly known as CERCLA or the "Superfund" law) imposes liability without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. In what is commonly known as the "petroleum exclusion", the definition of "hazardous substance" under CERCLA excludes “petroleum, including crude oil or any fraction thereof”. CERCLA liability attaches when three conditions are satisfied:
Persons who are, or were, responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the cost of cleaning up hazardous substances released into the environment, and for attendant damages to natural resources.
The right to develop oil and gas interests in the USA is typically conveyed or governed by an oil and gas lease (whereby an oil and gas exploration company leases minerals from a landowner) and/or a joint operating/unit operating agreement (whereby multiple "working-interest" owners agree on the manner of development for specified land).
Oil and Gas Leases
Under an oil and gas lease, the upstream company (the "lessee") receives a working interest that survives for as long as the lease remains in effect. The lessee’s working interest is a cost-bearing interest that typically provides the right to drill on the premises and retain the majority of the hydrocarbons extracted therefrom.
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; in Texas, marginal production will typically suffice (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. These include the following.
Given the potential for substantial capital expenditures by the lessee without meaningful or immediate production, modern oil and gas leases commonly include a number of defensive clauses that extend the term of the lease for some period of time without the necessity of production. Typical defensive clauses include the following:
In addition to essential clauses and defensive clauses, many oil and gas leases that cover a large acreage position include "Pugh" clauses, which ensure that a lessee does not maintain the entire leasehold area through a single producing well. A Pugh clause states that a producing well will hold only a specified area around that well, and thus, after the primary term, the mineral owner is free to re-lease the remaining/released land. The clause may take the form of either a vertical Pugh clause – limiting the lease to certain depths or geological formations – or a horizontal Pugh clause, specifying the surface area surrounding a producing oil and gas well that is held by production from such well (often the minimum area prescribed by state spacing rules). Many modern oil and gas leases with sophisticated landowners include both types.
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 risk of drilling a dry hole, oil and gas lessees can – and often do – convey development rights among themselves by sale, swap, farm-out, joint development agreements or other drilling arrangements, all of which can result in multiple working-interest owners in a single lease.
Joint Operating Agreements
A joint operating agreement (JOA) is a contract between two or more parties creating a contractual framework for the sharing of risk and reward for petroleum operations. JOAs are frequently based on a form issued by the American Association of Petroleum Landmen (AAPL), modified most recently in 1989 and 2015.
Though the 2015 AAPL JOA incorporates features relating to horizontal development, it remains common industry practice to utilise the 1989 AAPL JOA and manually adapt the form to reference horizontal development. While the JOA is a complex instrument and a full summary is beyond the scope of this article, certain key provisions from the 1989 AAPL JOA include the following.
Alternative Development Structures
Besides entering into a JOA, two or more lessees may agree upon alternative structures for the joint development/acquisition of specified properties, including defining development areas (usually well-defined areas where a specified party is designated as the operator of all operations undertaken by the developing parties), areas of mutual interest (if one party acquires an interest in properties within the AMI, then that party must offer a portion to the other party/ies on the same terms) and/or carried interests (one party pays the costs – typically drilling, exploration and operating costs – of the other party up to an agreed cap, usually until a certain dollar amount is spent by the "carrying" party).
Working-interest owners may also structure joint development through a farm-out agreement, which is a contract whereby an interest in land is conveyed in return for either testing or drilling operations on the land. The "farmor" is the person who provides the acreage and the "farmee" is the person who agrees to test and/or drill in order to obtain the interest in the acreage. Many farm-out agreements include drilling covenants whereby the farmee promises to drill, and can be held liable for the reasonable costs of drilling if they fail to do so. Alternatively, in a farm-out agreement that includes a drilling condition, the farmee only receives an interest in the property if he or she drills a test well. In such an event, there are no damages for the failure to drill, other than the farmee not receiving an interest in the property.
Similar to a farm-out, another structure to facilitate joint development is a drilling participation arrangement, commonly referred to as the "DrillCo" structure. DrillCo deals typically involve a commitment by the investor to fund an agreed share of capital costs to drill and complete wells in exchange for an undivided interest in the portion of the leasehold acreage required to produce from those wells (namely, a "wellbore" interest). Besides funding its respective ownership interest of drilling costs, the investor may be required to fund a portion of the operator’s share of drilling costs through a drilling "carry". Once the investor achieves a specified return, the majority of the wellbore interest typically reverts to the operator.
See 2.1 Forms of Allowed Private Investment in Upstream Interests and 2.3 Typical Fiscal Terms under Upstream Licences/Leases.
The process of permitting oil and gas wells varies across state and federal jurisdictions and tribal lands, with most being designed in some form to protect human health and the environment. Permits for onshore operations are typically required for the use of local roads, drilling, operating the well (subject to ongoing reporting requirements), sediment discharge and erosion control, the potential discharge of toxic substances into the air, and the protection of endangered species and stream crossing. Wells drilled in the waters of the Gulf of Mexico require more extensive permitting overseen by BSEE (ie, new well, bypass and sidetrack and revisions to the foregoing).
In order to receive the applicable permit, operators must demonstrate an ability to address a well blow-out and worst-case discharge, and newer permit applications for drilling projects now face heightened standards and scrutiny for well design, casing and cementing, and must be independently certified by a professional engineer.
Although there is no separate tax regime applicable to the petroleum industry, the federal income tax code, federal income tax regulations and the tax codes and regulations of many states have special provisions for the taxation of US upstream oil and gas operations, particularly with respect to the treatment of "intangible drilling and development costs" (IDCs) and "depletion".
IDCs are incurred by an operator when drilling or developing an oil and gas well, and can include the costs of drilling, wages, supplies, repairs and fuel. Because these costs are incurred in the development of wells that can provide a benefit to the taxpayer substantially beyond the end of the taxable year in which they are incurred, they are capital in nature and would ordinarily be recovered through depletion over the life of the asset. However, to encourage taxpayers to engage in the risky exploration and development of oil and gas wells, federal income tax law currently allows most taxpayers to make an election to expense and immediately deduct IDCs in the year they are incurred.
Depletion is a form of cost recovery that allows a taxpayer to recover the capitalised cost of an oil and gas asset over its useful life, and is calculated on a property-by-property basis. Federal income tax law generally provides for two forms of depletion. "Cost depletion" is available to all taxpayers and provides for the recovery of the tax basis in a mineral property as minerals from such property are produced and sold. "Percentage depletion" allows a deduction with respect to oil and gas assets equal to the product of 15% times the “gross income from the property” earned in a particular year.
Although integrated oil companies and oil and gas refiners and retailers are only permitted to take cost depletion, other taxpayers are currently allowed to use the depletion method that results in the larger deduction for a particular year. In practice, percentage depletion can be more beneficial to taxpayers as it may produce deductions in excess of the tax basis.
However, the Biden administration has proposed significant changes to the federal income tax laws and regulations applicable to US upstream oil and gas companies, including requiring IDCs to be capitalised rather than immediately expensed and eliminating the percentage depletion method. Although it is unclear whether any such changes will be enacted, they would likely have a significant adverse impact on the upstream oil and gas industry if enacted.
In addition to the federal income tax regime, most states and many localities impose income taxes and various other taxes throughout the oil and gas development and production cycle that are applicable to upstream oil and gas operations, including severance, production, ad valorem, property, excise, sales and use taxes.
Under US Federal Regulations, onshore federal oil and gas leases may only be held by adult US citizens, associations of US citizens (eg, as partnerships and trusts), US corporations and municipalities. At the time the lessee takes its interest in the lease, the lessee must certify to the BLM that it meets the requirements to be qualified to hold a BLM lease. The lessee does not need to provide evidence of its qualification at the time of certification, but the BLM may require the lessee to supply evidence that it meets the qualification requirements. The qualification requirements apply not only to leasehold interests (ie, record title interests), but also to other types of oil and gas property interests, such as overriding royalties, production payments, carried interests and net profit interests.
Section 1 of the Mineral Leasing Act and the associated regulations do not permit foreign corporations or non-US citizens to directly own federal oil and gas leases. If a non-citizen wishes to own federal oil and gas leases, it must do so through an agent or "nominee" corporation. Based on guidance from the Department of the Interior, the determinative requirement is that the holder of record title to the oil and gas leases must be a US corporation or US partnership.
In order to hold a US federal lease, the lessee must also submit a surety or personal bond to the BLM in the amount set out by federal regulations. The purpose of these bonds is to ensure that the lessee complies with the terms of the oil and gas lease and the federal performance standards (eg, completing and plugging wells and reclaiming and restoring lease areas). In most cases, lessees will utilise surety bonds issued by approved surety companies, although personal bonds or letters of credit are utilised in some cases.
For lessees who own large leasehold acreage positions, statewide and nationwide bonds may be utilised to cover the bonding requirements of multiple leases. The amount of the bonds may be increased if the BLM determines that the lessee poses a greater risk to oil and gas development, including, for example, a history of previous violations or non-payment of royalties. BLM bonds must remain in place and are binding upon the lessee until either an acceptable replacement bond has been filed or all the terms and conditions of the lease have been satisfied.
With respect to offshore oil and gas leases, although complex bonding requirements apply that are in excess of the onshore requirements, lessees are subject to the same qualification requirements under the BOEM regulations as described for the BLM (above).
While the regulation of oil and gas operations at the local government level is generally limited, one notable exception is Colorado, which on 16 April 2019 changed state pre-emption laws and expanded local governments’ jurisdiction over oil and gas within the state. Colorado Senate Bill 19-181 makes three important changes to prior law:
Senate Bill 19-181 was signed into law on 16 April 2019. This bill expands local governments’ jurisdiction over oil and gas within the state, and clarifies that local governments have powers to regulate siting, land and surface impacts, and all nuisance-type issues related to the industry, as well as the ability to inspect facilities and impose fines.
The bill also changes state pre-emption law by empowering local governments to enact regulations that are more protective or stricter than state requirements, and clarifying that the main state-level regulatory body, the COGCC, does not have exclusive authority over oil and gas regulations; instead, the COGCC shares authority with local governments and other state agencies to regulate oil and gas activities. Consistent with this framework, Senate Bill 19-181 also requires operators to seek permission from the relevant local government before they can obtain a state permit.
The BLM’s administration of federal leases relies on the concepts of “record title” and “operating rights.” The record title-holder is the person or entity who is contractually linked to the government either as lessee or as its assignee or sublessee, while the person or entity holding the operating rights has the authority to actually conduct operations on the lease. In addition to record title and operating rights, a party may hold other interests, including 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. In an assignment of operating rights, the assignee must also submit the required bond.
This is not applicable in the USA.
See 2.7 Requirements for a Licence/Lease-Holder to Proceed to Development and Production.
See 6.4 Material Changes in Oil and Gas Law or Regulation.
See 1.1 System of Petroleum Ownership.
This is not applicable in the USA.
This is not applicable in the USA.
See 1.1 System of Petroleum Ownership.
Although there is no separate tax regime applicable to the petroleum industry, the federal income tax code, federal income tax regulations and the tax codes and regulations of many states include special provisions that allow entities engaged in certain specified activities with respect to minerals or natural resources to be publicly traded partnerships, which are commonly referred to as master limited partnerships or MLPs. Absent such special provisions, federal income tax law otherwise requires publicly traded entities to be taxed as corporations.
The vast majority of MLPs are found in the midstream space. MLPs are treated as partnerships that do not pay tax at the entity level so long as 90% of their income is “qualifying income”, which includes income derived from the exploration, development, mining or production, processing, refining, transportation and marketing of minerals and natural resources. Rather, the income, gains, losses and deductions of an MLP flow through to its unit-holders. Non-corporate unit-holders of an MLP are also generally eligible for a 20% deduction on the net income passed through from the MLP to such unit-holder under current law.
The Biden administration has proposed changes to the federal income tax laws applicable to midstream oil and gas companies. In particular, the tax reform proposal provides that publicly traded partnerships with qualifying income from fossil fuel-related activities would be taxed as corporations for taxable years beginning after 31 December 2026. Notably, the tax reform proposal also includes an increase of the tax rate for all corporations from 21% to 28%. Although it is unclear whether any such changes will be enacted, they could have a material and adverse impact on the midstream oil and gas industry if enacted.
Unlike the tax regimes applicable to US upstream and midstream oil and gas operations, the federal income tax code, federal income tax regulations and the tax codes and regulations of states generally do not have special provisions for the taxation of US downstream oil and gas operations, but such operations would also be subject to taxation by most states and many localities, including with respect to ad valorem, property, excise, sales and use taxes.
This is not applicable in the USA.
This is not applicable in the USA.
This is not applicable in the USA.
Under Section 7(h) of the NGA, the holder of a certificate of public convenience and necessity from FERC may exercise the right of eminent domain over the land or other property necessary to construct pipelines and other infrastructure contemplated by the FERC certificate. To exercise that right, the certificate-holder must file a condemnation action in the US District Court for the district in which the condemned property is located or in the applicable state’s court system. The court will then determine the level of just compensation that the certificate holder must provide the property owner for the condemned property according to the laws of the state in which the condemned property is located.
Unlike the NGA, the ICA confers no federal eminent domain rights for interstate oil and liquids pipelines.
This is not applicable in the USA.
This is not applicable in the USA.
See 6.2 Liquefied Natural Gas (LNG) Projects.
This is not applicable in the USA.
A foreign business must create one or more wholly-owned US entities through which it may acquire the leasehold interests in order to hold an oil and gas interest in a federal lease. However, there is no single, federal system in the USA governing the formation of such entities, and any new entity(ies) will be formed in and administered subject to the laws of a particular state. The state of formation may be the state where the property is owned or business is conducted, but that is not mandatory.
For example, if an entity is organised under the laws of Delaware but conducts commercial business in Texas, then that entity must comply with the relevant laws of both states. Thus, the entity would be formed and do business in accordance with Delaware law, but would take steps to allow it to be recognised and authorised to do business in Texas, and most of its third-party business dealings and property ownership would be governed by Texas law. The choice of where to form a controlling entity, and perhaps form other sub-entities thereunder, often turns on key tax considerations.
Through the Committee on Foreign Investment in the US (CFIUS), parties to a prospective acquisition, merger or takeover may provide the US President with a voluntary joint notification of an acquisition, merger or takeover by a non-US entity. By submitting the voluntary notification, a transaction with national security implications will undergo review and receive US government approval or disapproval before the transaction is completed. Where parties to a prospective transaction do not provide voluntary notice to CFIUS, the committee has the authority to initiate its own review of the transaction and to recommend to the US President the unwinding of the transaction after it has been consummated.
Once CFIUS has received a completed formal joint notification, it will conduct a 30-day review to determine whether the proposed acquisition could harm the national security of the USA. If the committee determines that the transaction raises significant national security issues, it will undertake a more thorough 45-day investigation, after which time a report is issued to the US President, who will decide within 15 days whether or not to block the acquisition.
Oil and gas interests are also subject to the Foreign Investment in Real Property Tax Act (FIRPTA) regime, which generally subject non-US holders of oil and gas interests to federal withholding tax at a rate of 15% of the gross proceeds received upon a disposition of such interests.
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 derived from primary field operations 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 has published permitting guidance addressing the use of diesel in fracturing operations. In addition, the EPA issued guidance regarding federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. Furthermore, numerous states have adopted regulations that require disclosure of at least some of the chemicals in the fluids used in hydraulic fracturing or well-stimulation operations; other states are considering adopting such regulations.
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 2020 the EPA issued rules revising and rescinding the methane requirements for certain sources in the production and processing segments of the oil and gas industry. The 2020 rules are subject to pending litigation that has been held in abeyance pending a review of the rules by the EPA. In response to President Biden’s Executive Order 13990, issued January 20, 2021, the EPA has begun a broad public outreach effort to gather community and stakeholder input regarding potential changes to the methane rules for new and existing sources in the oil and natural gas industry
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’s 2016 Waste Prevention rule was vacated by the US District Court for the District of Wyoming on October 8, 2020 for intruding on EPA’s authority to regulate methane. California and environmental groups have appealed the decision, which remains pending in the Court of Appeals for the Tenth Circuit. In addition, in September 2018, the BLM issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations. The repeal was invalidated by the US District Court for the Northern District of California, which decision remains on appeal before the Court of Appeals for the Ninth Circuit.
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, including, most notably, California, Colorado, Utah, Wyoming and Texas.
Certain states have also developed tailored regulatory requirements to address unique environmental impacts that could be associated with oil and gas production activities. For example, since 2015, the Oklahoma Corporation Commission has issued several directives establishing volume, depth and disposal rate restrictions for saltwater disposal wells, in order to reduce the potential for seismic activity in "areas of interest" near targeted underground injection sites. In certain instances, the commission has also ordered for specific wells to be "shut in" due to the enhanced seismicity risk associated with underground injection activities. In February 2018, the commission issued additional requirements for operators to have access to a seismic array during drilling activities in certain shale-producing areas, and to comply with certain protocols – including temporary cessation of operations – during seismic events (with basic requirements triggered during earthquakes of magnitude 2.0 or greater).
Additionally, the Railroad Commission of Texas requires applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilising the US Geological Survey, which are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The Commission is authorised to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Commission is also considering new restrictions that could limit the volume and pressure of produced water injected into disposal wells.
See 5.1 Principal Environmental Laws and Environmental Regulator(s).
Numerous federal and state statutes and regulations, maritime law actions, as well as common law, can impose liability for a release of oil. 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 USD137.6595 million for damages, provided certain conditions are met, with no limit on the responsible parties’ liability for removal costs. The limit of liability was adjusted by BOEM on 18 January 2018, to reflect inflation occurring since 1990. The incident involving the D Horizon drilling rig and its Macondo Prospect well is the only incident to have resulted in damages known to exceed the statutory liability limit for an offshore facility.
Other laws that impose liability for an offshore release of oil include the Clean Water Act, OCSLA, the National Marine Sanctuaries Act (NMSA), the Refuse Act of 1899, the Migratory Bird Treaty Act, the Endangered Species Act and the Marine Mammal Protection Act (MMPA). While some of these statutes include limits on liability, the responsible party must prove that it meets the applicable criteria to receive the benefit of such limitations.
Some states bordering offshore waters, including Texas and California, also have oil pollution acts that do not include a cap on damages. In addition to liability for response costs and damages, responsible parties may also be held liable for large civil and criminal fines and penalties under state and federal statutes, including penalties of up to three times the actual cost of removal, and sizeable penalties 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) or emissions trading schemes could be implemented.
Regulations of GHG emissions have changed substantially over the past two administrations. During the Obama administration, the EPA enacted rules requiring the monitoring and reporting of GHG emissions from a wide variety of major sources under the Clean Power Plan (CPP). These rules included onshore and offshore oil and natural gas production facilities, and onshore oil and natural gas processing, transmission, storage, and distribution facilities. Reporting of GHG emissions from such facilities was required on an annual basis. The Supreme Court limited such reporting to sources that were already regulated under Title V of the Clean Air Act, and stayed implementation of the CPP.
In 2019, EPA repealed the CPP and replaced it with the Affordable Clean Energy (ACE) rule, which relaxed certain requirements of the CPP. In January 2021, the Court of Appeals for the District of Columbia Circuit (DC Circuit) vacated the ACE rule and the decision is on appeal before the Supreme Court. In February 2021, the EPA issued a memorandum stating its position that neither the CPP nor the ACE rule are currently in effect and the DC Circuit granted the EPA’s request to delay reinstating the CPP while it reviews the rule.
In March 2021, FERC formally considered the impacts of climate change in its approval of an approximately 87-mile interstate natural gas pipeline project. FERC conducted its analysis by comparing the pipeline project’s reasonably foreseeable GHG emissions to the total GHG emissions in the USA as well as to the emissions totals in the two states in which the proposed facilities were going to be built. Based on these comparisons, FERC concluded that the pipeline project’s contribution to climate change would not be significant and granted the requested NGA certificate without expressly weighing the climate change impacts against the pipeline project’s benefits.
FERC noted that the newly announced policy would continue to evolve, and that, in future cases where it finds impacts on climate change to be significant, such impacts would be considered along with numerous other factors to determine if the project is required by the public convenience and necessity. Thus, 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.
Partly in response to the uncertainty raised in climate change-related litigation, in June 2019, the White House’s Council on Environmental Quality (CEQ), which is responsible for promulgating NEPA regulations, issued proposed guidance for how agencies should consider greenhouse gas emissions and the related climate impacts when conducting NEPA analyses, including that (i) a “but for” causal relationship is not sufficient to render an indirect effect a “reasonably foreseeable” result of the proposed federal action, and (ii) agencies need not provide a quantitative analysis of effects where the information necessary to do so is unavailable, not of high quality, or so complex as to be overly speculative nor conduct a monetary cost-benefit analysis using "social cost of carbon" estimates or other similar cost metrics. In January 2021, CEQ rescinded the 2019 guidance, and the agency is reviewing the 2016 Greenhouse Gas Emissions and the Effects of Climate Change in NEPA Reviews guidance for potential updates. In the interim, federal agencies may rely upon the 2016 guidance, which directs the agencies to evaluate the effects of a proposed action on climate change.
In July 2020, CEQ amended the NEPA implementing regulations for the first time in the 40 years since NEPA was enacted. The revisions were primarily intended to streamline the environmental review process to shorten the time for review. In addition, the revised rules eliminated the requirement to evaluate cumulative impacts, which may impact the requirement for federal agencies to evaluate the potential impact of a project on GHG emissions and climate change. The revised rules were challenged by environmental organisations, but the US District Court for the Western District of Virginia dismissed the challenges as unripe because the revised rules have not yet been applied to a specific project. CEQ is reconsidering the revised rules.
See 2.6 Local Content Requirements Applicable to Upstream Operations.
See 1.1 System of Petroleum Ownership.
The USA has become a major LNG exporter in recent years.
Companies seeking to import or export natural gas to or from the USA, via an onshore facility, are required by the NGA to obtain authorisation from FERC and the DOE/FE. However, the regulatory requirements are different for offshore LNG facilities.
Pursuant to Sections 3(a) and 3(c) of the NGA, FERC authorises the siting, construction and operation of onshore LNG import and export facilities in the USA. FERC authorises the siting, construction and operation of such facilities if it finds the project will not be inconsistent with the public interest. In making this determination, FERC conducts a review of the project’s environmental impacts, as required by NEPA.
In conducting its NGA and NEPA reviews, FERC consults with other relevant federal agencies regarding compliance with other statutes and regulations pertaining to environment, health and safety. The FERC approval process for LNG import and export facilities in recent years has typically taken around 18 to 36 months.
In addition, Section 3(a) of the NGA requires prior approval from DOE/FE for a person to import or export natural gas to or from the USA. The DOE/FE evaluates applications to import or export to or from countries with which the USA has free trade agreements (FTA countries) differently from applications to import or export to countries without FTAs (non-FTA countries).
Pursuant to Section 3(a) of the NGA, LNG imports or exports to or from FTA countries are deemed to be in the public interest, and DOE/FE is required to authorise applications for such imports or exports without modification or delay. According to the Office of the US Trade Representative, the USA has free trade agreements with 20 countries, including Australia, Canada and Mexico. The DOE/FE approval process for applications to import or export to or from FTA countries in recent years has typically taken between one and five months.
In contrast, applications to import or export LNG to or from non-FTA countries are granted only upon a finding by DOE/FE that the proposed imports or exports are not inconsistent with the public interest. The public interest standard includes consideration of the price, the need for natural gas, and the security of the natural gas supply. The DOE/FE approval process for applications to export to non-FTA countries in recent years has generally taken two to three years. There have not been any import licence requests to import LNG from non-FTA countries since 2011.
See 6.4 Material Changes in Oil and Gas Law or Regulation.
Over the last several years, as a wave of restructurings has swept through the industry, many upstream and midstream companies have started to re-evaluate their current agreements, particularly their midstream agreements.
In the Sabine Oil & Gas Chapter 11 proceeding, 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 objections from the midstream entities.
While several subsequent bankruptcy cases (ie, Badlands Energy, Inc. and In re Alta Mesa Res., Inc.) have pushed back against the Sabine ruling in an apparent return to the conventional understanding that gathering agreements do create covenants running with the land, a few prominent recent bankruptcy cases have signalled that a midstream agreement may be permitted to be rejected irrespective of whether it is a covenant that runs with the land or not (eg, Extraction, Chesapeake and Southland).
FERC’s Issuance of Tolling Orders and the Construction of FERC-Regulated Natural Gas and LNG Infrastructure
Historically, FERC issued orders – commonly referred to as “tolling orders” – to provide itself additional time to consider arguments raised in requests for rehearing, while permitting construction activities to proceed before FERC concluded its review. While FERC’s issuance of tolling orders had been upheld for decades, the US Court of Appeals for the DC Circuit issued an opinion in June 2020 invalidating FERC’s issuance of tolling orders in this way.
In Order No 871, FERC revised its regulations to preclude the agency from authorising the holder of an NGA certificate to proceed with construction of FERC-approved interstate natural gas pipeline and LNG facilities until (i) FERC acts on the merits of timely filed requests for rehearing or (ii) the time to seek rehearing has passed without any requests for rehearing being submitted.
In May 2021, FERC further revised its regulations to prohibit the issuance of authorisations to proceed with construction if a timely request for rehearing of the underlying certificate order that specifically opposes project construction operation or need has been received, until:
US Council on Environmental Quality (CEQ) Proposed NEPA Greenhouse Gas Guidance and Implementing Regulations
Over the past few years, there has been significant litigation over federal agencies’ responsibility to consider climate change impacts when conducting NEPA reviews of federal activities related to oil and natural gas, and the scope of those obligations remains unsettled.
In July 2020, CEQ issued a notice of final rule-making to amend the NEPA implementing regulations, shortening the time for agencies to conduct their review, eliminating the requirement to evaluate cumulative impacts, and implementing the One Federal Decision policy – rule changes it has since begun reconsidering – and in January 2021, the Biden administration revoked Executive Order 13807, indicating an intention to advocate for a detailed permitting and environmental review process for new projects.
Biden Administration Updates: Actions on Energy, Environmental and Climate Issues
President Biden has moved quickly to implement his climate and environmental agenda since taking office, ordering numerous actions that could impact the energy and infrastructure sectors. Some of his more notable actions include the following:
Federal agencies are also directed to consider additional regulation, including new EPA regulations to establish comprehensive standards of performance and emission guidelines for methane and VOC emissions from existing operations in the oil and gas sector by September 2021.
CO₂ Sequestration: Why Louisiana Is the Right Place at the Right Time
Governments and businesses worldwide are seeking solutions to limit the release of carbon dioxide (CO₂) into the atmosphere, and to either geologically sequester the CO₂ on a permanent basis or temporarily store the compound as a potential resource for future applications. Given their processes and products, energy and chemical companies are particularly interested in pursuing advanced carbon capture and sequestration – and Louisiana offers an ideal location for these activities. The arguments in favour of Louisiana as a model for, and centre of, CO₂ capture and sequestration activities fall into three primary categories: geography and geology, alignment of federal and Louisiana state laws and regulations, and existing energy and chemical infrastructure.
Geography and Geology
Much of Louisiana lies above subsurface porous areas (or “pore spaces”) that are typically filled with saline water. Some of these pore spaces are naturally occurring, while others are the result of prior petroleum and natural-gas extraction activities. Furthermore, a significant percentage of these areas can be found in state-controlled waters and land. Louisiana is also home to a number of geological formations known as salt domes.
These and similar sites can serve as ideal locations for the permanent geological sequestration of CO₂ (in pore spaces) or for the temporary storage of CO₂ (in salt domes) where the by-product can be injected and removed as necessary. And as technologies for sequestering and storing CO₂ are beginning to proliferate, many such processes are being designed explicitly to take advantage of these naturally occurring geological areas.
Alignment of Federal and Louisiana State Laws and Regulations
Two primary areas of law play a key role in supporting Louisiana’s viability as a centre for permanent CO₂ geological sequestration (which is the focus of this article): environmental regulations and land ownership.
Under the Underground Injection Control (UIC) programme, the US Environmental Protection Agency (EPA) is tasked with protecting underground sources of drinking water in instances where an injection well is being utilised to inject fluid into an underground geological formation. The EPA categorises injection wells into six classifications, with Class VI covering wells for the injection and geological sequestration of CO₂. In general, to drill any of the six classes of injection wells, an entity must apply for a permit with the EPA. However, the EPA may also grant to states the primary authority to administer the UIC programme in so far as it concerns specific classes of wells, with this delegation of primary authority to a state being known as state “primacy”. Presently, Louisiana has primacy for Class I–V wells, but it has not obtained primacy for Class VI wells. The Louisiana Department of Natural Resources (LDNR) has submitted its application and associated proposed rules seeking primacy to issue Class VI permits for CO₂ sequestration projects in Louisiana. The EPA has approved LDNR’s draft regulations – which generally mirror the current EPA Class VI regulations – and the EPA has noticed the draft regulations for public comment. Presently, Louisiana expects to achieve primacy by the end of 2021 or the first quarter of 2022.
Separate and apart from regulating and permitting the Class VI injection wells, the regulation of the land and reservoirs where the CO₂ sequestration will occur resides primarily with the states. With this in mind, Louisiana passed the Louisiana Geologic Sequestration of Carbon Dioxide Act in 2009 (the “CO₂ Sequestration Act”). The primary objective of the CO₂ Sequestration Act was to establish a public policy supportive of CO₂ sequestration, which the Act states is for the “benefit [of] the citizens of the [S]tate and the [S]tate’s environment”. The CO₂ Sequestration Act establishes the roles and responsibilities of the Louisiana Commissioner of Conservation as the primary regulator of CO₂ sequestration, and it provides detailed guidance regarding the determination that a reservoir is appropriate for CO₂ sequestration, the issuance of various certificates, hearing procedures, liability issues, and more.
To further expound on the key role played by these areas of law in supporting Louisiana’s viability as a centre for CO₂ sequestration, a review of the general process to put a CO₂ sequestration project into operation is helpful. In general, to put a project into operation, there are three prerequisites that must be satisfied:
Obtain the necessary pore-space rights
From a landowner’s perspective, under the Louisiana Civil Code, the ownership of a tract of land generally includes everything directly above or below that tract of land. The Louisiana Mineral Code does provide some specific nuances to this general rule as related to minerals and mineral rights, but in so far as the pore space under a property is concerned, the general rule is that the owner of the tract of land also owns the pore space underneath that land.
For a CO₂ sequestration project in Louisiana, an operator may need to obtain pore-space rights from one of three possible sources:
Process to obtain pore-space rights from private landowners
Under Louisiana law, various types of agreements may be used to acquire the necessary pore-space rights for a CO₂ sequestration project, including fee-title ownership, a servitude, or a lease. There are pros and cons to each of these methods that must be explored before deciding on a particular means for acquisition, but often, a servitude is the preferred method due to the permanent nature of the sequestration. Although a servitude expires after ten years of non-use under Louisiana law, the parties can define the “use” broadly in the servitude agreement, and thus the servitude could be held indefinitely, so long as CO₂ is being sequestered in the pore space.
To the extent there are any hold-outs, the CO₂ Sequestration Act explicitly states that a storage operator may exercise eminent domain to acquire rights to pore space and certain ancillary rights necessary to operate a CO₂ sequestration facility, provided certain prerequisites are satisfied. Under the CO₂ Sequestration Act, a storage operator can exercise eminent domain to acquire the “surface and subsurface rights and property interests necessary or useful for the purpose of constructing, operating, or modifying a storage facility and the necessary infrastructure”. The CO₂ Sequestration Act broadly defines the term “storage facility” to include:
And, as part of this expropriation power, operators are explicitly given the right to expropriate the rights necessary for pipelines used to transport the CO₂ to a storage facility.
The CO₂ Sequestration Act mandates that prior to exercising eminent domain, the storage operator obtain a certificate of public convenience and necessity from the Commissioner of Conservation. Before the storage operator obtains the certificate of public convenience and necessity, a public hearing must be held in the parish where the storage facility is to be located, during which the Commissioner of Conservation must determine that the storage facility “is required by the present or future public convenience and necessity”. The CO₂ Sequestration Act specifies that this finding must be based on the storage facility’s meeting the requirements of La. R.S. § 30:1104(C) and any other relevant rules adopted pursuant to the CO₂ Sequestration Act. (These same findings must also be made prior to the use of any storage reservoir for CO₂ sequestration, regardless of whether eminent domain will be exercised.)
The CO₂ Sequestration Act states that after the certificate of public convenience and necessity is issued, eminent domain is to be exercised pursuant to the procedures found in La. R.S. § 19:2, which are the general procedures for pipeline and other condemnation proceedings.
Process to obtain pore-space rights from the State of Louisiana
On public land and water bottoms owned or administrated by the State of Louisiana, the State Mineral and Energy Board has been vested with all authority to grant the necessary state property interests required for CO₂ sequestration. Essentially, obtaining the required surface and subsurface rights from the state is “one-stop shopping”.
There are two options for obtaining the pore-space rights required for CO₂ sequestration or storage on state land or water bottoms:
With an operating agreement, and unlike a lease, there are fewer statutory limitations on the ultimate agreement that can be reached between the parties, allowing for more customisation of the agreement to meet the needs of the project. In effect, the process encompasses informal negotiations between the staff of the State Mineral and Energy Board and the applicant, with multiple instances of review, oversight, and approvals or disapprovals by, and at meetings of, the State Mineral and Energy Board.
Alternatively, the State Mineral and Energy Board can lease any and all state land or water bottoms for sequestration through a bid process. However, there are statutory limitations on the lease, including a 25-year time limitation on any potential lease, with an option to extend it for another 25-year term. Additionally, there is less freedom to customise the ultimate agreement in a lease-bid process.
Process to obtain pore-space rights from the federal government
Finally, in general, a party can obtain pore-space rights to federal property through a lease, special-use permit, or other similar agreement or process, depending on which federal agency has the authority to lease or allow the activity on the specific federal property. Therefore, it is important to determine which federal agency or agencies have the authority to grant the rights that are sought.
Obtain state regulatory approval to use the reservoir for CO₂ sequestration
In addition to obtaining the pore-space rights, an operator must obtain approval from the Louisiana Office of Conservation to use the pore space to sequester CO₂.
Prior to using any reservoir to sequester CO₂, the Commissioner of Conservation must conduct a public hearing in the parish where the CO₂ sequestration or storage facility will be located, and the Commissioner of Conservation must make certain findings after that public hearing that centre around:
Obtain a Class VI well permit
In addition to obtaining pore-space rights and state regulatory approval, the applicant must obtain a Class VI well permit for the injection well. As discussed above, to obtain a Class VI well permit in Louisiana, the applicant presently must file the permit application with the EPA, as Louisiana does not have primacy for Class VI wells. However, LDNR has submitted its application and associated proposed rules seeking primacy to issue Class VI permits for CO₂ sequestration projects, and Louisiana presently expects to achieve primacy by the end of 2021 or the first quarter of 2022. Once Louisiana obtains primacy, applicants will submit Class VI permit applications to the Office of Conservation, Injection and Mining Division, for review and approval.
Existing Energy and Chemical Infrastructure
In addition to the legal and regulatory structure in Louisiana, the energy and chemicals industries have long had a significant presence in Louisiana. Much of the extensive existing infrastructure – including production, refining and manufacturing facilities, pipelines, and other hard assets – that has been developed to support these two industries can be repurposed to reduce emissions and support CO₂ sequestration.
The Road Ahead
In addition to the numerous Louisiana-specific factors that contribute to the business case for the development and implementation of CO₂ sequestration facilities in the state, the federal government has created a number of incentives designed to generate momentum for these technologies. The prime example of these incentives is the “45Q” tax credit, which provides a tax credit based on the metric tons of qualified CO₂ that are captured and sequestered. (For the 45Q tax credit, qualified CO₂ is CO₂ “that would have been released into the atmosphere if not for the qualifying equipment”.) In 2018, through the Bipartisan Budget Act of 2018, Congress expanded and extended the 45Q tax credit.
This confluence of advantages – including geological formations ideal for CO₂ sequestration, the alignment of state and federal laws and regulations, the unique system of land and resource ownership in Louisiana, and the existing tax benefits – has positioned Louisiana to serve as a centre for the sequestration of CO₂.