NORTHERN OIL & GAS, INC. (NOG) Business

Item 1. Business

Overview

We are an independent energy company engaged as a non-operator in the acquisition, exploration, development and production of oil and natural gas properties in the United States, primarily in the Williston Basin, the Permian Basin, the Appalachian Basin and the Uinta Basin. We believe the location, size and concentration of our acreage positions in some of North America’s leading unconventional oil and gas resource plays provide us with drilling and development opportunities that will result in significant long-term value. We currently report a single reportable segment. See “Financial Statements” and the notes to our financial statements for financial information about this reportable segment.

Our primary strategy is to invest in non-operated minority working and mineral interests in oil and natural gas properties, with a core area of focus in the premier basins within 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 natural gas producers.

We seek to create value through strategic acquisitions and financially participating alongside operators who have significant experience in developing and producing hydrocarbons in our core areas. We have more than 100 experienced operating partners that provide technical insights and opportunities for acquisitions. Across these operators, no single operator represented more than 11% of our fourth quarter 2025 oil and natural gas sales.

Prior to 2020, we focused our operations exclusively on oil-weighted properties in the Williston Basin. Since then we have significantly grown and diversified our properties via acquisitions of oil and natural gas properties in the Permian Basin, Appalachian Basin and Uinta Basin. See Note 3 to our financial statements for information regarding our recent acquisition activities. Our acquisition activities were a significant driver of our 6% production growth from 131,777 Boe per day in the fourth quarter of 2024 to 140,064 Boe per day in the fourth quarter of 2025.

The following table provides a summary of certain information regarding our assets as of December 31, 2025, including reserves information audited by our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc. (“Cawley”).

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(1)Represents the average daily production over the three months ended December 31, 2025.

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Business Strategy

Our business strategy is focused on growing our reserves, production and free cash flow to create long-term value for our stakeholders while maintaining a strong balance sheet. The key elements of our business strategy include the following:

•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 across multiple basins. As of December 31, 2025, we have participated in 11,702 gross (1,195 net) producing wells with an average working interest of 10.2% in each gross well, with more than 100 experienced operating partners. We also believe that we can further diversify our risk with acquisitions in multiple basins, focusing on accretive acquisitions of top-tier assets with top-tier operators in the premier basins in the United States. For the three months ended December 31, 2025, 42% of our production was from the Permian Basin, 30% was from the Williston Basin, 21% was from the Appalachian Basin and 7% was from the Uinta Basin.

•Accelerate Growth by Pursuing Value-Enhancing Acquisitions.  We strive to be the natural consolidator and clearing house of non-operated working interests 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 production growth. We intend to continue these activities, while at the same time evaluating and pursuing larger non-operated asset packages that we believe can responsibly add significant production, cash flow and scale to existing operations.

•Build and Maintain a Strong Balance Sheet and Proactively Manage to Limit Downside Risk.  We strive for financial strength and flexibility through the prudent management of our balance sheet. Changes in commodity prices, as well as the timing of various investment and financing opportunities, result in changes to our leverage over time. However, we manage the business with the long-term goal of maintaining leverage at or near our target of 1.0x Debt / Adjusted EBITDA.

•Systematic Hedging Strategy. 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. We have a rolling target of hedging 65% or more of our anticipated next 18-month production.

•Stockholder Returns. The foregoing strategies are collectively aimed at building a diversified, low-leverage, cash generating business that can deliver meaningful returns to our investors. We have provided stockholder returns in the form of cash dividends and security repurchases, and will seek to grow stockholder returns over time.

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 trade sanctions, taxation, energy, climate change and the environment, geopolitical instability and armed conflicts (including between Russia and Ukraine and 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 natural 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.

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining

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prices, associated cost declines are likely to lag and may not adjust downward in proportion. Additionally, ongoing inflationary pressures have resulted in and may result in additional increases to the costs of goods, services and personnel. Material changes in prices impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Sustained levels of high inflation caused the U.S. Federal Reserve to increase the federal funds interest rate by 5.25% to a high of 5.375% between March 2022 and July 2023 in an effort to curb inflationary pressure on the costs of goods and services. While inflationary pressures in the United States’ economy have begun to subside, inflation is still holding above the U.S. Federal Reserve’s target level. Further, despite the U.S. Federal Reserve decreasing the federal funds interest rate to 3.625% between September 2024 and December 2025, we continue to be impacted by the elevated federal funds interest rate, which could additionally have the effects of raising the cost of capital and depressing economic growth.

Development

As a non-operator, 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 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 decisions with respect to our participation in well proposals.

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 our production is sold is generally tied to the spot market for oil or natural gas. The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price. 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. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX benchmark price. Using our commodity hedging program, from time to time we 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 add 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 and storage 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.

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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.  Our indebtedness under our Revolving Credit Facility 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 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 generally do not own physical real estate, but, instead, our acreage is primarily 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. Many of our leases are or were 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 business is 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

The oil and natural gas exploration, production and related operations that we participate in as a non-operator are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies.  For example, many states 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.  Many states 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. 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 our operating partners can drill.  Moreover, many states impose a production or severance tax

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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 level in relation to changes in industry costs.  The current price index covers the five-year period which commenced on July 1, 2021.

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, the Natural Gas Policy Act of 1978 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. Interstate transportation services, however, remain subject to FERC regulation, including with respect to rates, terms and conditions of service, and authorizations to build new, or abandon old, facilities. A primary aim of FERC’s regulation of interstate natural gas transportation is to prevent undue discrimination among shippers, and so we do not anticipate that FERC regulation will affect our operations in any way that is materially different from those of similarly situated competitors.

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

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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, tribal 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. These laws and regulations may:

•require the acquisition of a permit or other authorization and procurement of financial assurance 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 our 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.

The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on several categories of persons, including current and former 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” if properly handled, such exploration and production wastes could be reclassified in the future 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 the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. Accordingly, restrictions may be imposed on exploration and production operations, as well as actions by federal agencies, to avoid significantly impairing or jeopardizing the species or its habitat.  The ESA provides for criminal penalties for willful violations of the ESA.  The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. However, in April 2025, the U.S. Fish and Wildlife Service and National Marine Fisheries Service proposed to redefine “harm” to mean affirmative acts that are directed immediately and intentionally against a particular animal, excluding acts or omissions that indirectly cause injury. Additionally, in November 2025, the Trump Administration proposed several rules that would significantly alter ESA protections for plants and animals. One proposed rule would rescind a rule that automatically extends protections for endangered species to threatened species. Another proposed rule would change regulations for listing species as endangered or threatened as well as for designating critical habitats. Additionally, a third proposed rule would reinstate the framework for evaluating the benefits and cost of designating a critical habitat by considering factors like economic impact, impact on national security, and other relevant impacts. The U.S. Fish and Wildlife Service is expected to issue final rules in 2026. 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, future amendments are uncertain, and 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

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significant expenses to modify our operations or could force discontinuation of certain operations altogether. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations.

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 November 2021, the Environmental Protection Agency (“EPA”) issued a proposed rule intended to revise and add to the NSPS program rules, known as Subpart OOOOa. The proposed rule sought to formally reinstate methane (a greenhouse gas (“GHG”)) emission limitations for existing and modified facilities in the oil and gas sector under Subparts OOOOa and OOOOb and sought to also regulate existing oil and gas facilities for the first time. Under Subpart OOOOc, the EPA’s proposed rule sought to require states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule sought to remove an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring system to flag large emissions events, referred to in the proposed rule as “super emitters.” In December 2023, the EPA announced a final rule, later published in March 2024, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, until March 2026 to develop and submit their plans for reducing methane emissions from existing sources. However, in March 2025, the EPA announced its intention to reconsider the March 2024 rule, including Subparts OOOOb and OOOOc, with a final rule expected in or around July 2026. A subsequent rule, finalized on November 26, 2025, gives states, along with federal tribes that wish to regulate existing sources, until January 2027 to develop and submit their plans for reducing methane emissions from existing sources. Additionally, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of these rules remains uncertain at this time. At the same time, 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 GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. Any regulations or proposals requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition.

At the international level, the United Nations-sponsored Paris Agreement requires signatory countries to set voluntary targets to reduce domestic GHG emissions. While the United States withdrew from the Paris Agreement during the Trump Administration in 2020, the Biden Administration recommitted the United States to the Paris Agreement in January 2021 and established a goal of reducing GHG emissions by at least fifty percent from 2005 levels by 2030. However, in January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. Additionally, in January 2026, the Trump Administration announced the formal withdrawal of the United States from the United Nations Framework Convention on Climate Change in a presidential memorandum. The full impact of these actions remains unclear at this time. At the same time, various state and local governments have publicly committed to furthering the goals of the Paris Agreement and, many related initiatives are expected to continue at the local, state and international levels.

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. In January 2023, the EPA and the U.S. Army Corps of Engineers (the “USAC”) issued a final rule that based the definition of WOTUS on a pre-2015 definition, which never took effect before being replaced in 2020. Separately, in May 2023, the U.S. Supreme Court’s decision in Sackett v. EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface

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connection” with or are otherwise indistinguishable from traditional navigable water. In September 2023, the EPA and the Corps published a direct-to-final rule that conforms the regulatory definition of WOTUS to the Supreme Court’s May 2023 decision in Sackett. However, roughly half of the states and other plaintiffs are challenging the September 2023 rule, and the EPA and the Corps are using the pre-2015 definition of WOTUS in these states while litigation continues. In November 2025, the Corps and the EPA proposed another rule revising the definition of WOTUS to conform to the Supreme Court’s decision in Sackett by providing clarity on terms such as “relatively permanent,” “tributary,” and “continuous surface connection.” As a result, substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of CWA jurisdiction more generally. Any expansion to CWA jurisdiction could impact areas where oil and gas operations are conducted. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. In 2021, the United States Supreme Court held that the CWA requires a discharge permit if the addition of pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. In November 2023, the EPA issued draft guidance describing the information that should be used to determine which discharges through groundwater may require a permit. However, in January 2025, President Trump issued executive orders directing (i) the EPA and the Corps to identify planned or potential actions that could be subject to emergency treatment under Section 404 of the CWA and (ii) the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including all existing regulations and guidance documents, that are unduly burdensome on the identification, development, or use of domestic energy resources. Accordingly, on January 15, 2026, the EPA published a proposed rule to revise the Section 401 state and tribal water quality certification regulations. The proposed rule aims to narrow the “activity”-based scope of state and tribal certification to point source discharges into waters of the United States. The public comment period concludes on February 17, 2026. Future implementation and enforcement of these rules and policies is uncertain at this time. Additionally, costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans.

The CAA, 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 is regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act and programs under comparable state statutes. 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 but not passed in recent sessions of Congress. The EPA has issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the Underground Injection Control (“UIC”) program, specifically as “Class II” UIC wells, and prohibits the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.

Scrutiny of hydraulic fracturing activities continues in other ways.  The federal government continues to study hydraulic fracturing’s potential impacts.  Several states, including states where we have properties, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing.  A number of municipalities in other states, including Colorado and Texas, have attempted to enact bans on hydraulic fracturing. 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, it 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 NEPA. Some activities are subject to robust NEPA review which could lead to delays and increased costs that could materially adversely affect our revenues and results of operations. Other activities are covered under categorical exclusions which results in a shorter NEPA review process. In April 2022, the White House Council on Environmental Quality (“CEQ”) finalized the first of two planned rules to undo changes to NEPA enacted in 2020 under the Trump Administration. The Phase I Final Rule generally restores certain regulatory provisions that were in effect prior to the 2020 rule, affecting the assessment of projects ranging from oil and gas leasing to development on public and Indian lands. Additionally, in September 2023, the Biden Administration announced that federal

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agencies will be directed to consider the Social Cost of GHGs in agency budgeting, procurement, and other agency decisions, including in environmental reviews conducted pursuant to NEPA, where appropriate. In May 2024, CEQ finalized the Phase II rule, which generally restores certain mitigation language from the pre-2020 version of the NEPA regulations, proposes further revisions, and meets environmental, environmental justice, and climate change objectives. However, at least twenty states challenged the Phase II rule in federal district court. In January 2025, President Trump issued executive orders directing (i) CEQ to provide guidance on implementing NEPA and to propose rescinding and replacing CEQ’s NEPA regulations with implementing regulations at the agency level; (ii) federal agencies to adhere to only the relevant legislated requirements for environmental reviews and to prioritize efficiency and certainty over any other objectives in such reviews; and (iii) the EPA to issue guidance on and consider eliminating the Social Cost of GHG calculation from federal permitting or regulatory decisions. In February 2025, CEQ sent an interim final rule to the White House Office of Management and Budget that would immediately withdraw the NEPA implementing regulations. In January 2026, CEQ formally repealed its NEPA implementing regulations on the basis of the Supreme Court’s decision in Seven County Infrastructure Coalition v. Eagle County, Colorado. In Seven County, the Supreme Court directed lower courts to give “substantial deference” to reasonable agency conclusions underlying its NEPA process. Accordingly, the January 2026 rule is meant to streamline NEPA review, and has left the July 2020, Phase I, and Phase 2 rules in place. The January 2026 rule may be subject to litigation. Congress is also considering legislation designed to streamline NEPA through the Standardizing Permitting and Expediting Economic Development Act (“SPEED Act”). The SPEED Act aims to redefine what qualifies as a “major Federal action” and impose stricter deadlines for NEPA review. The SPEED Act has passed the House of Representatives and passage remains pending and uncertain. The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our business and operations.

Climate Change

In the United States, no comprehensive federal climate change legislation regulating GHG emissions or directly imposing a price on carbon has been implemented to date; however, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. These include the Paris Agreement, a treaty adopted at the 21st United Nations Conference of the parties that is aimed at addressing climate change with member countries agreeing to nationally determine their contributions and set GHG emission reduction goals every five years and the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030. However, in January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. Additionally, in January 2026, the Trump Administration announced the formal withdrawal of the United States from the United Nations Framework Convention on Climate Change in a presidential memorandum. The full impact of these actions remains unclear at this time. At the same time, many state and local leaders have intensified or stated their intent to intensify efforts to support international climate commitments and treaties, in addition to considering or enacting laws requiring the disclosure of climate-related information and developing programs that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes or encouraging the use of renewable energy or alternative lower-carbon fuels. Although the Supreme Court’s decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. and end the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, many of these initiatives at the international, state and local levels are expected to continue.

Further, legislative and regulatory initiatives are underway to that purpose. The Inflation Reduction Act of 2022 (“IRA”), signed into law in August 2022, appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a Waste Emissions Charge (“WEC”) on GHG emissions from certain oil and gas sources and facilities. To implement the program, in May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. Among other things, the new rule expands the emissions events that are subject to reporting requirements to include “other large release events” and applies reporting requirements to certain new sources and sectors. The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program in the IRA. However, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit has commenced. In addition, in November 2024, the EPA finalized a rule to implement the IRA’s WEC. However, in January 2025, the Trump Administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. In addition, in March 2025, President Trump signed Congress’ Joint Resolution of Disapproval of the WEC, and in May 2025, EPA issued a final rule to remove the WEC regulations from the Code of Federal Regulations. In July 2025, the One Big Beautiful Bill Act delayed the effective date of the WEC until 2034.

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The U.S. Congress has also considered legislation that would control GHG emissions through a “cap and trade” program and several states have already implemented programs to reduce GHG emissions.  Additionally, following the U.S. Supreme Court finding that GHG emissions fall within the CAA definition of an “air pollutant,” the EPA has adopted regulations that, among other things, establish construction and operating permit review for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, and together with the United States Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. The EPA also finalized rules in December 2023 intended to reduce methane emissions from new and existing oil and gas sources and in January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of liquified natural gas to non-free trade agreement countries until the Department of Energy can update the underlying analyses for authorizations, including an assessment of the impact of GHG emissions. The Department of Energy released its report on liquified natural gas exports in December 2024, which report is subject to a 60-day public comment period ending in February 2025. However, in January 2025, President Trump issued executive orders directing (i) the Department of Energy to restart reviews of applications for approvals of liquefied natural gas export projects as expeditiously as possible; (ii) the EPA and the heads of any other relevant federal agencies to submit joint recommendations to the Office of Management and Budget regarding the continuing applicability of the GHG endangerment finding of 2009; and (iii) the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Additionally, in September 2025, the EPA proposed to permanently remove program obligations from the Greenhouse Gas Reporting Program for most source categories, and suspend program obligations for some sources subject to subpart W (which applies to emission sources in certain segments of the petroleum and natural gas industry) until 2034. The full impact of these orders remains uncertain at this time. At the same time, many state and local leaders have intensified or stated their intent to intensify efforts to support international climate commitments and treaties, in addition to considering or enacting laws requiring the disclosure of climate-related information and developing programs that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes or encouraging the use of renewable energy or alternative lower-carbon fuels.

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 revised and expanded NSPS, also known as Subpart OOOOa, to include final rules to curb emissions of methane, a GHG, from new, reconstructed and modified oil and gas sources. Previously, already existing NSPS regulated VOCs, and controlling VOCs also had the effect of controlling methane, because natural gas leaks emit both compounds. However, by explicitly regulating methane as a separate air pollutant, the 2016 regulations were a statutory predicate to propose regulating emissions from existing oil and gas facilities. In 2021, the EPA proposed rules to regulate methane emissions from the oil and natural gas industry, including, for the first time, reductions from certain upstream and midstream existing oil and gas sources under Subparts OOOOa and OOOOb. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rules, removing an emissions monitoring exemption for small wellhead-only sites and creating a new third-party monitoring program to flag large emissions events. In December 2023, the EPA announced a final rule, later published in March 2024, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for certain Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, until March 2026 to develop and submit their plans for reducing methane emissions from existing sources. However, in March 2025, the EPA announced its intention to reconsider the March 8, 2024 rule, including Subparts OOOOb and OOOOc, with a final rule expected in or around July 2026. A subsequent rule, finalized on November 26, 2025, gives states, along with federal tribes that wish to regulate existing sources, until January 2027 to develop and submit their plans for reducing methane emissions from existing sources. The final rule is subject to ongoing litigation but remains in effect. Additionally, in January 2025, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) finalized a rule that requires pipelines, underground natural gas storage facilities, and liquefied natural gas facilities to update leak detection and repair programs to require companies to use commercially available technologies to find and fix methane leaks from pipelines and other facilities. PHMSA and the Department of Interior continue to focus on regulatory initiatives to control methane emissions from upstream and midstream equipment. To the extent that these regulations or initiatives 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. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of these rules remains uncertain at this time.

In addition, our third-party operating partners may be required to report their GHG 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

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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.

Human Capital Resources

As of December 31, 2025, we had 64 full time employees. We may hire additional personnel as appropriate.  We may also use the services of independent consultants and contractors to perform various professional services from time to time.

We strive to attract, develop and retain the best talent and spend considerable time and resources to advance the professional development and security of our workforce. We operate on the fundamental philosophy that people are our most valuable asset, as every person who works for us has the potential to impact our success. We believe employees choose to work at the Company in part due to our engaging culture, competitive compensation and benefits, and professional development opportunities. To attract and retain the best talent, we provide our employees a comprehensive total rewards program, including opportunities for share ownership in the Company. In addition to competitive salaries, we offer both short and long-term incentive compensation; company-matched 401(k) contributions; company-paid premiums for health, dental and vision insurance, short and long-term disability insurance, and life insurance; and company-supported health savings accounts and flexible spending accounts. The Company also provides a generous match for employee donations to qualifying charitable organizations, and organizes employee volunteer days from time to time. We offer many additional programs to support the wellness of our workforce, including an onsite fitness center within our executive offices, company-provided lunches, and a flexible paid time off and vacation policy.

We recognize the importance of investing in our employees’ professional development and are committed to ensuring that all employees are prepared for every aspect of their day-to-day roles. We have a multi-year rotational analyst development program, to ensure that we are hiring and developing new talent and offering cross-functional exposure and learning experience. This program was designed with the intent of developing an internally trained pool of future leaders that have a holistic view of our systems, processes and operations. We also support employees who seek to further their professional development through appropriate external educational programs and offer tuition reimbursement benefits for various extended educational learning opportunities.

We are committed to providing a workplace environment free of discrimination and harassment, where all individuals are treated with respect and dignity, can contribute fully, and have equal opportunities. We value and strive to treat all employees, consultants, vendors, contractors, service providers, and business partners equally. We prohibit discrimination or harassment on the basis of any grounds prohibited by law. We are committed to maintaining employment practices based on equal opportunity for all employees and providing a safe and productive working environment for all employees. Our policies and practices are designed to promote diversity of thought, perspective, and professional experience, and to support all employees fairly without regard to disability, sexual orientation, gender, gender identity and expression, religion, race, ethnicity, culture, and nationality, among others.

Office Locations

Our executive offices are located at 4350 Baker Road, Suite 400, Minnetonka, Minnesota 55343.  Our office space consists of 24,641 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 (the “DGCL”) and our Delaware certificate of incorporation and bylaws.

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Available Information – Reports to Security Holders

Our website address is www.noginc.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 Bylaws, Acquisition Committee Charter, Audit Committee Charter, Compensation Committee Charter, Executive Committee Charter, Governance, Nominating and ESG Committee Charter, Corporate Governance Guidelines, Stock Ownership Guidelines, Code of Business Conduct and Ethics, Insider Trading Policy, Clawback Policy, Related Person Transaction Approval Policy, ESG Policy, Anti-Corruption and Bribery Policy, Human Rights Statement, Political Contributions and Trade Associations Policy and our Compliance Hotline, in addition to all pertinent company contact information.

We use our website as a channel of distribution for important Company information. We routinely post important information, including presentation materials and press releases, to our corporate website, www.noginc.com, including the investor relations section thereof. We also use our website to expedite public access to time-critical information regarding our Company in advance of or in lieu of distributing a press release or a filing with the SEC disclosing the same information. When permissible, we expect to continue to do so without also providing disclosure of this information through filings with the SEC. Therefore, investors should look to our website for important and time-critical information.

Where we have included Internet addresses in this Annual Report on Form 10-K, we have included those Internet addresses as inactive textual references only. Except as specifically incorporated by reference into this Annual Report on Form 10-K, information on those websites is not part hereof.