Item 1. Business
Item 1. Business
Overview
We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties, primarily in the Bakken and Three Forks formations within the Williston Basin in North Dakota and Montana. We believe the location, size and concentration of our acreage position in one of North America’s leading unconventional oil-resource plays provide us with drilling and development opportunities that will result in significant long-term value.
Our primary focus is investing in non-operated minority working and mineral interests in oil and gas properties in the United States. As a non‑operator, we are able to diversify our investment exposure by participating in a large number of gross wells, as well as entering into additional project areas by partnering with numerous experienced operating partners or pursuing value‑enhancing acquisitions. In addition, because we can generally elect to participate on a well‑by‑well basis, we believe we have increased flexibility in the timing and amount of our capital expenditures because we are not burdened with various contractual arrangements with respect to minimum drilling obligations. Further, we are able to avoid exploratory and infrastructure costs incurred by many oil and gas producers.
We seek to create value through strategic acquisitions and partnering with operators who have significant experience in developing and producing hydrocarbons in our core areas. We have more than 40 experienced operating partners that provide technical insights and opportunities for acquisitions. Across these operators, no single operator represented more than 15% of our net producing wells as of December 31, 2020. We had historically focused entirely in the Williston Basin of the United States, in North Dakota and Montana, where substantially all of our assets were located as of December 31, 2020. We expanded our strategy in 2020, making our first small acquisitions in the Permian Basin. In February 2021, we entered into an agreement to acquire producing natural gas properties in the Appalachian Basin from Reliance Marcellus, LLC (the “Reliance Acquisition”), which we anticipate will close in April 2021. See Note 14 to our financial statements for further details regarding the pending Reliance Acquisition.
The following table provides a summary of certain information regarding our assets as of December 31, 2020, including reserves information as estimated by our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc.:
As of December 31, 2020
Net
Acres Productive Wells Average Daily Production(1)
(Boe per day) Proved Reserves
(MBoe) % Oil % Proved Developed
Gross Net
Williston Basin 183,242 6,633 474.5 35,583 119,523 78 % 69 %
Permian Basin 285 7 0.6 155 3,109 82 54
Total 183,527 6,640 475.1 35,738 122,632 78 % 69 %
__________________
(1) Represents the average daily production over the three months ended December 31, 2020.
2
Table of Contents
Business Strategy
Key elements of our business strategies include:
• Diversify Our Risk Through Non-Operated Participation in a Large Number of Wells and Multiple Basins . As a non-operator, we seek to diversify our investment and operational risk through participation in a large number of oil and gas wells and with multiple operators. As of December 31, 2020, we have participated in 6,640 gross (475.1 net) producing wells with an average working interest of 7.2% in each gross well, with more than 40 experienced operating partners. We believe the best way to develop our acreage is to take a long-term approach and to participate in the development of our locations with potential for the highest rates of return while preserving optionality to allocate capital to assets in our portfolio that offer the highest projected rates of return. We also believe that we can further diversify our risk with acquisitions in other basins, which we began in 2020 in the Permian Basin and expect to continue in 2021, including via the pending Reliance Acquisition.
• Accelerate Growth by Pursuing Value-Enhancing Acquisitions. We strive to be the natural consolidator and clearing house of non-operated working interest in various leading oil and gas shale plays in the United States. Our “ground game” acquisition strategy is to build a strong presence in our core basins and seek to acquire smaller additional lease positions at a significant discount to the contiguous acreage positions typically sought by larger producers and operators of oil and gas wells, focusing on near term drilling opportunities. Such acquisitions have been a significant driver of our net well additions and additions to production. We intend to continue these activities, while at the same time evaluating and pursuing larger non-operated asset packages, such as the pending Reliance Acquisition, that we believe can responsibly accelerate our growth strategy.
• Build and Maintain a Strong Balance Sheet and Proactively Manage to Limit Downside. We strive for financial strength and flexibility through the prudent management of our balance sheet. Additionally, given the volatility of the commodity price environment, we employ an active commodity price risk management program to better enable us to execute our business plan over the entire commodity price cycle.
Industry Operating Environment
The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of taxation, energy, climate change and the environment, political and social developments in the Middle East, demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source.
Oil and natural gas prices have been, and we expect may continue to be, volatile. Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or gas prices may affect planned capital expenditures and the oil and natural gas reserves that we can economically produce. Lower oil and gas prices may also reduce the amount of our borrowing base under our revolving credit facility, which is determined at the discretion of the lenders based on various factors including the collateral value of our proved reserves. While lower commodity prices may reduce our future net cash flow from operations, we expect to have sufficient liquidity to continue development of our oil and gas properties. In addition, we undertake an active commodity hedging program that is designed to help stabilize the volatile commodity pricing environment and protect cash flows in a potential downturn.
Development
We primarily engage in oil and natural gas exploration and production by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage. In addition, we acquire wellbore-only working interests in wells in which we do not hold the underlying leasehold interests from third parties unable or unwilling to participate in particular well proposals. We typically depend on drilling partners to propose, permit and initiate the drilling of wells. Prior to commencing drilling, our partners are required to provide all owners of oil, natural gas and mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share of such interest within the spacing unit. We assess each drilling opportunity on a case-by-case basis and participate in wells that we expect to meet our return thresholds based upon our estimates of ultimate recoverable oil and natural gas, expected oil and gas prices, expertise of the operator, and completed well cost from each project, as well as other factors. Historically, we have participated pursuant to our working interest in a vast majority of the wells proposed to us. However, declines in oil prices typically reduce both the number of well proposals we receive and the proportion of well
3
Table of Contents
proposals in which we elect to participate. Our land and engineering team uses our extensive database to make these economic decisions. Given our large acreage footprint and substantial number of well participations, we believe we can make accurate economic drilling decisions.
Historically, we have not managed our commodities marketing activities internally. Instead, our operating partners generally market and sell oil and natural gas produced from wells in which we have an interest. Our operating partners coordinate the transportation of our oil and gas production from our wells to appropriate pipelines or rail transport facilities pursuant to arrangements that they negotiate and maintain with various parties purchasing the production. We understand that our partners generally sell our production to a variety of purchasers at prevailing market prices under separately negotiated short-term contracts. Although we have historically relied on our operating partners for these activities, we may in the future seek to take a portion of our production in kind and internally manage the marketing activities for such production. The price at which production is sold generally is tied to the spot market for oil. Williston Basin Light Sweet Crude from the Bakken source rock is generally 41-42 API crude oil and is readily accepted into the pipeline infrastructure. Our weighted average oil price differential during 2020 was $6.63 per barrel below NYMEX pricing. This differential primarily represents the transportation costs in moving the oil from wellhead to refinery and will fluctuate based on availability of pipeline, rail and other transportation methods. Using our commodity hedging program, we may, from time to time, enter into financial hedging contracts to help mitigate pricing risk and volatility with respect to differentials.
Competition
The oil and natural gas industry is intensely competitive and we compete with numerous other oil and natural gas exploration and production companies, many of which have substantially greater resources than we have and may be able to pay more for exploratory prospects and productive oil and natural gas properties. Our larger or integrated competitors may be better able to absorb the burden of existing, and any changes to federal, state, and local laws and regulations than we can, which would adversely affect our competitive position. Our ability to discover reserves and acquire additional properties in the future is dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Marketing and Customers
The market for oil and natural gas that will be produced from our properties depends on many factors, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
Our oil production is expected to be sold at prices tied to the spot oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We rely on our operating partners to market and sell our production. Our operating partners include a variety of exploration and production companies, from large publicly-traded companies to small, privately-owned companies. We do not believe the loss of any single operator would have a material adverse effect on our company as a whole.
Title to Properties
Our oil and natural gas properties are subject to customary royalty and other interests, liens under indebtedness, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. A significant portion of our indebtedness, including under our revolving credit facility and senior secured notes, is also secured by liens on substantially all of our assets. We do not believe that any of these burdens materially interfere with the use of our properties or the operation of our business.
We believe that we have satisfactory title to or rights in our producing properties. As is customary in the oil and gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. In most cases, we investigate title only when we acquire producing properties or before commencement of drilling operations.
Seasonality
Winter weather conditions and lease stipulations can limit or temporarily halt the drilling and producing activities of our operating partners and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt the operations of our operating partners and materially increase our operating and capital costs. Such
4
Table of Contents
seasonal anomalies can also pose challenges for meeting well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operating partners’ operations.
Principal Agreements Affecting Our Ordinary Business
We do not own any physical real estate, but, instead, our acreage is comprised of leasehold interests subject to the terms and provisions of lease agreements that provide our company the right to participate in drilling and maintenance of wells in specific geographic areas. Lease arrangements that comprise our acreage positions are generally established using industry-standard terms that have been established and used in the oil and natural gas industry for many years. Some of our leases may be acquired from other parties that obtained the original leasehold interest prior to our acquisition of the leasehold interest.
In general, our lease agreements stipulate three-to-five year terms. Bonuses and royalty rates are negotiated on a case-by-case basis consistent with industry standard pricing. Once a well is drilled and production established, the leased acreage in the applicable spacing unit is considered developed acreage and is held by production. Other locations within the drilling unit created for a well may also be drilled at any time with no time limit as long as the lease is held by production. Given the current pace of drilling in the areas of our operations, we do not believe lease expiration issues will materially affect our acreage position.
Governmental Regulation and Environmental Matters
Our operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as whole.
Regulation of Oil and Natural Gas Production
Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota and Montana require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Moreover, the current administration has indicated that it expects to impose additional federal regulations limiting access to and production from federal lands. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.
Regulation of Transportation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost of service filing. Every five years, the FERC reviews the appropriateness of the index
5
Table of Contents
level in relation to changes in industry costs. On December 17, 2015, the FERC established a new price index for the five-year period which commenced on July 1, 2016.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is generally governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.
Onshore gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Environmental Matters
Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:
• require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;
• limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and
• impose substantial liabilities for pollution resulting from its operations.
The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general.
6
Table of Contents
The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. Recent regulation and litigation that has been brought against others in the industry under RCRA concern liability for earthquakes that were allegedly caused by injection of oil field wastes.
The Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of ESA. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company (directly or indirectly through our operating partners) to significant expenses to modify our operations or could force discontinuation of certain operations altogether.
The Clean Air Act (“CAA”) controls air emissions from oil and natural gas production and natural gas processing operations, among other sources. CAA regulations include New Source Performance Standards (“NSPS”) for the oil and natural gas source category to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities.
In recent years, there has been considerable uncertainty surrounding regulation of methane emissions, as the EPA previously published final regulations under the Clean Air Act establishing new performance standards for methane in 2016, but since that time the EPA has undertaken several measures, including issuing rules in 2020, to delay implementation of the methane standards. Various states and industry and environmental groups are separately challenging both the original 2016 standards and the EPA’s 2020 final rule. Notwithstanding the current court challenges, the EPA under the current administration may reconsider the 2020 final rule, which could result in more stringent methane emission rulemaking. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored Paris Agreement, which is a non-binding agreement for nations to limit their greenhouse gas emissions through individually-determined reduction goals every five years after 2020. While the United States withdrew from the Paris Agreement effective November 4, 2020, President Biden recommitted the United States to the Paris Agreement on January 20, 2021.
These regulations and proposals and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition.
The Federal Water Pollution Control Act of 1972, or the Clean Water Act (the “CWA”), imposes restrictions and controls on the discharge of produced waters and other pollutants into waters of the United States (“WOTUS”). Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. The CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and gas industry into certain coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge permit. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. CWA jurisdiction depends on the definition of WOTUS. This definition has been in flux since 2015, when US EPA and the Army Corps of Engineers enacted regulations to more broadly define WOTUS, thereby potentially expanding CWA jurisdiction. The 2015 WOTUS rule is subject to numerous legal challenges, which have left the new definition in place in 26 states but enjoined in 24 states, including Montana and North Dakota. Furthering uncertainty about CWA jurisdiction, in February 2019, US EPA and the Army Corps of Engineers proposed a replacement WOTUS rule circumscribing CWA jurisdiction. This rule will likely also be challenged once it is finally promulgated. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Although the
7
Table of Contents
federal CWA is currently interpreted not to regulate discharges to groundwater, on February 21, 2019, the United States Supreme Court accepted jurisdiction to review the case County of Maui v. Hawaii Wildlife Fund , No. 18-260, which raises the question whether the federal CWA regulates pollutants that originate from a point source but are only conveyed to navigable water through groundwater. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges, for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.
The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Substantially all of the oil and natural gas production in which we have interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act to address hydraulic fracturing operations.
Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts. Several states, including Montana and North Dakota where our properties are located, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities in other states, including Colorado and Texas, have enacted bans on hydraulic fracturing. New York State’s ban on hydraulic fracturing was recently upheld by the Courts. In Colorado, the Colorado Supreme Court has ruled the municipal bans were preempted by state law. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, which could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our revenue and results of operations.
The National Environmental Policy Act (“NEPA”) establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA. Many of the activities of our third-party operating partners are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and on March 12, 2012, issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.
Climate Change
Significant studies and research have been devoted to climate change, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production.
In the United States, no comprehensive federal climate change legislation has been implemented to date but the current administration has indicated willingness to pursue new climate change legislation, executive actions or other regulatory initiatives to limit greenhouse gas (“GHG”) emissions. Further, legislative and regulatory initiatives are already underway to that purpose. The U.S. Congress has considered legislation that would control GHG emissions through a “cap and trade” program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the CAA definition of an “air pollutant.” Recent litigation has held that if a source was subject to Prevention of Significant Deterioration (“PSD”) or Title V based on emissions of conventional pollutants like sulfur dioxide, particulates, nitrogen dioxide, carbon monoxide, ozone or lead, then the EPA could also require the source to control GHG emissions and the source would have to install Best Available Control Technology to do so. As a result, a source may still have to control GHG emissions if it is an otherwise regulated source.
In 2014, Colorado was the first state in the nation to adopt rules to control methane emissions from oil and gas facilities. In 2016, the EPA issued three final rules that were intended to curb emissions of methane, VOCs and toxic air pollutants such as benzene from new, reconstructed and modified oil and gas sources. These regulations include leak detection
8
Table of Contents
and repair provisions, and may require controls to reduce methane emissions from certain oil and gas facilities. To the extent that these regulations remain in place and to the extent that our third party operating partners are required to further control methane emissions, such controls could impact our business.
In addition, our third party operating partners are required to report their greenhouse gas emissions under CAA rules. Because regulation of GHG emissions continues to evolve, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Moreover, while the U.S. Supreme Court held in its 2011 decision American Electric Power Co. v. Connecticut that, with respect to claims concerning GHG emissions, the federal common law of nuisance was displaced by the CAA, the Court left open the question of whether tort claims against sources of GHG emissions alleging property damage may proceed under state common law. There thus remains some litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. Although operators may take steps to mitigate physical risks from storms, no assurance can be given that future storms will not have a material adverse effect on our business.
Human Capital Resources
As of December 31, 2020, we had 25 full time employees. We may hire additional personnel as appropriate. We also may use the services of independent consultants and contractors to perform various professional services.
Office Locations
Our executive offices are located at 601 Carlson Pkwy, Suite 990, Minnetonka, Minnesota 55305. Our office space consists of 8,295 square feet of leased space. We believe our current office space is sufficient to meet our needs and that additional office space can be obtained if necessary.
Organizational Background
On May 9, 2018, we filed articles of conversion with the Secretary of State of the State of Minnesota and filed a certificate of conversion with the Secretary of State of the State of Delaware changing our jurisdiction of incorporation from Minnesota to Delaware (the “Reincorporation”). The Reincorporation was approved by our stockholders at a special meeting held on May 8, 2018. Upon the Reincorporation, each outstanding certificate representing shares of the Minnesota corporation’s common stock was deemed, without any action by the holders thereof, to represent the same number and class of shares of our company’s common stock. As of May 9, 2018, the rights of our stockholders began to be governed by Delaware General Corporation Law and our Delaware certificate of incorporation and bylaws.
Available Information – Reports to Security Holders
Our website address is www.northernoil.com . We make available on this website, free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. Electronic filings with the SEC are also available on the SEC internet website at www.sec.gov.
We have also posted to our website our Audit Committee Charter, Compensation Committee Charter, Nominating Committee Charter and our Code of Business Conduct and Ethics, in addition to all pertinent company contact information.
9
Table of Contents