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What changed in NORTHERN OIL & GAS, INC.'s 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of NORTHERN OIL & GAS, INC.'s 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.

+364 added−345 removedSource: 10-K (2024-02-23) vs 10-K (2023-02-24)

Top changes in NORTHERN OIL & GAS, INC.'s 2023 10-K

364 paragraphs added · 345 removed · 290 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

53 edited+29 added−13 removed98 unchanged
Biggest changeWe 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.
Biggest changeWe 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.
Item 1. Business Overview We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties in the United States, primarily in the Williston Basin, the Appalachian Basin and the Permian Basin.
Item 1. Business Overview We are an independent energy company engaged 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 and the Appalachian Basin.
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, we may, from time to time, enter into financial hedging contracts to help mitigate pricing risk and volatility with respect to differentials.
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.
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, and the Biden Administration has indicated willingness to pursue new climate change legislation, executive actions or other regulatory initiatives to limit GHG emissions.
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, and the Biden Administration has indicated willingness to pursue new climate change legislation, executive actions or other regulatory initiatives to limit GHG emissions.
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 and regulations issued under those statutes.
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.
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 95 experienced operating partners that provide technical insights and opportunities for acquisitions.
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 105 experienced operating partners that provide technical insights and opportunities for acquisitions.
Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.
Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in increased legal, accounting and financial 9 Table of Contents compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.
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. Available Information – Reports to Security Holders Our website address is www.northernoil.com .
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. Available Information – Reports to Security Holders Our website address is www.noginc.com.
In October 2021, the Biden Administration proposed a Phase 1 rule to undo 2020 changes to NEPA enacted under the Trump Administration. The Phase 1 rule is the first of two planned rules to roll back the 2020 rule and was finalized on April 20, 2022.
In October 2021, the Biden Administration proposed a Phase 1 rule to undo 2020 changes to NEPA enacted under the Trump Administration. The Phase 1 rule is the first of two planned rules to roll back the 2020 rule and was finalized in April, 2022.
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.
Insofar as such regulation within a particular state will generally affect all intrastate natural gas 6 Table of Contents 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.
The following table provides a summary of certain information regarding our assets as of December 31, 2022, including reserves information audited by our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc. (“Cawley”).
The following table provides a summary of certain information regarding our assets as of December 31, 2023, including reserves information audited by our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc. (“Cawley”).
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.
Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and 8 Table of Contents 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.
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.
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 10 Table of Contents GHG emissions alleging property damage may proceed under state common law. There thus remains some litigation risk for such claims.
If additional levels of regulation and permits were required through the adoption of new laws and regulations at the 8 Table of Contents 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.
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.
While the United States withdrew from the Paris Agreement during the Trump Administration, President Biden recommitted the United States to the Paris Agreement on January 20, 2021 and established a goal of reducing economy-wide net GHG emissions by at least thirty percent from 2020 levels by 2030.
While the United States withdrew from the Paris Agreement during the Trump Administration in 2020, President Biden recommitted the United States to the Paris Agreement in January 2021 and established a goal of reducing economy-wide net GHG emissions by at least thirty percent from 2020 levels by 2030.
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, Governance, Nominating and ESG Committee Charter, Corporate Governance Guidelines, Code of Business Conduct and Ethics and Insider Trading Policy, in addition to all pertinent company contact information. 11 Table of Contents
Electronic filings with the SEC are also available on the SEC internet website at www.sec.gov. 11 Table of Contents We have also posted to our website our Bylaws, Audit Committee Charter, Compensation Committee Charter, Governance, Nominating and ESG Committee Charter, Executive Committee Charter, Acquisition Committee Charter, Corporate Governance Guidelines, Code of Business Conduct and Ethics, Insider Trading Policy and Clawback Policy, in addition to all pertinent company contact information.
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 5 Table of Contents regulations can result in substantial penalties.
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 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.
The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. 4 Table of Contents Our oil production is expected to be sold at prices tied to the spot oil markets.
Such acquisitions have been a significant driver of our net well additions and additions to production.
Such acquisitions have been a significant driver of our net well additions and production growth.
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 to include final rules to curb emissions of methane, a greenhouse gas, from new, reconstructed and modified oil and gas sources.
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 greenhouse gas, from new, reconstructed and modified oil and gas sources.
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 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.
Furthermore, many state and local leaders have intensified or stated their intent to intensify efforts to support 9 Table of Contents international climate commitments and treaties, in addition to 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 low-carbon fuels.
Furthermore, 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 low-carbon fuels.
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.
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.
Across these operators, no single operator represented more than 20% of our fourth quarter 2022 oil and natural gas sales. Prior to 2020, we focused our operations exclusively on oil-weighted properties in the Williston Basin. We first expanded beyond the Williston Basin in 2020, with several small acquisitions in the Permian Basin.
Across these operators, no single operator represented more than 20% of our fourth quarter 2023 oil and natural gas sales. Prior to 2020, we focused our operations exclusively on oil-weighted properties in the Williston Basin.
Specifically, EPA’s proposed new rules would require states to implement plans that meet or exceed emission federally established emission reduction guidelines for oil and natural gas facilities. On November 11, 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.
In addition, under Subpart OOOOc, the EPA’s proposed rule would require states to implement plans that meet or exceed federally established emission reduction guidelines for oil and natural gas facilities. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.
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.
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.
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 4 Table of Contents rely on our operating partners to market and sell our production.
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.
As of December 31, 2022, we have participated in 8,672 gross (799.3 net) producing wells with an average working interest of 9.2% in each gross well, with more than 95 experienced operating partners.
As of December 31, 2023, we have participated in 9,765 gross (951.6 net) producing wells with an average working interest of 9.7% in each gross well, with more than 105 experienced operating partners.
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.
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. 7 Table of Contents 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.
In furtherance of this EO, EPA on November 2, 2021 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. These regulations also expanded controls to reduce methane emissions, such as enhancement of leak detection and repair provisions.
In furtherance of this EO, in November 2021, 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.
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. 6 Table of Contents 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.
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.
Moreover, the Biden 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.
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 5 Table of Contents the locations at which we can drill.
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. The EPA is expected to issue a final rule by August 2023.
These regulations also expanded controls to reduce methane emissions, such as enhancement of leak detection and repair provisions. 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.
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.
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.
On November 2, 2021, the Environmental Protection Agency (“EPA”) proposed to revise and add to the NSPS program rules. The proposed rules would formally reinstate methane (a greenhouse gas (“GHG”)) emission limitations for existing and modified facilities in the oil and gas sector and would also regulate, for the first time under the NSPS program, existing oil and gas facilities.
The proposed rule would formally reinstate methane (a greenhouse gas (“GHG”)) emission limitations for existing and modified facilities in the oil and gas sector under Subpart OOOOa and would also regulate, for the first time under Subpart OOOOb, existing oil and gas facilities.
For the three months ended December 31, 2022, our production consisted of approximately 44,028 Boe per day in the Williston Basin, 22,696 Boe per day in the Permian Basin, and 12,130 Boe per day in the Appalachian Basin. • Accelerate Growth by Pursuing Value-Enhancing Acquisitions.
For the three months ended December 31, 2023, 46% of our production was from the Williston Basin, 44% was from the Permian Basin and 10% was from the Appalachian Basin. • Accelerate Growth by Pursuing Value-Enhancing Acquisitions.
Since its formal launch at the 26 th United Nations Climate Change Conference, over 150 countries have joined the pledge. Additionally, on March 21, 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors.
Additionally, on March 21, 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors.
We offer many additional programs to support the wellness of our workforce, including an onsite fitness center at our executive offices, a flexible paid time off and vacation policy, and a flexible remote work policy.
We offer many additional programs to support the wellness of our workforce, including an onsite fitness center at our executive offices 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.
Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third- 7 Table of Contents party monitoring system to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA is currently expected to issue a final rule by August 2023.
Among other things, the November 2022 supplemental proposed rule removes 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, 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.
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.
We have a rolling target of hedging 60% 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.
See Notes 3 and 14 to our financial statements for further details regarding these acquisitions. Our acquisition activity was a significant driver of our production growth from 64,155 Boe per day in the fourth quarter of 2021 to 78,854 Boe per day in the fourth quarter of 2022.
Our acquisition activity was a significant driver of our 45% production growth from 78,854 Boe per day in the fourth quarter of 2022 to 114,363 Boe per day in the fourth quarter of 2023.
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 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.
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.
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.
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 60% or more of our anticipated next 18-month production. • Stockholder Returns .
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.
Office Locations Our executive offices are located at 4350 Baker Road, Suite 400, Minnetonka, Minnesota 55343. Our office space consists of 15,751 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.
We believe our current office space is sufficient to meet our needs and that additional office space can be obtained if necessary.
As of December 31, 2022 Net Acres Productive Wells Average Daily Production (1) (Boe per day) Proved Reserves (MBoe) % Oil % Proved Developed Gross Net Williston Basin 182,168 7,487 608.0 44,028 186,165 70 % 69 % Permian Basin 17,616 818 92.8 22,696 53,116 62 72 Appalachian Basin 59,186 367 98.5 12,130 91,528 — 52 Total 258,970 8,672 799.3 78,854 330,809 49 % 65 % __________________ (1) Represents the average daily production over the three months ended December 31, 2022. 2 Table of Contents 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.
As of December 31, 2023 Net Acres Productive Wells Average Daily Production (1) (Boe per day) Proved Reserves (MBoe) % Oil % Proved Developed Gross Net Williston Basin 180,642 7,981 643.7 52,413 142,700 70 % 79 % Permian Basin 36,576 1,387 207.6 50,601 119,069 59 66 Appalachian Basin 55,034 397 100.3 11,349 77,926 — 57 Total 272,251 9,765 951.6 114,363 339,695 50 % 69 % __________________ (1) Represents the average daily production over the three months ended December 31, 2023. 2 Table of Contents 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.
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.
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.
Federal Reserve and other central banks to increase interest rates multiple times in 2022 in an effort to curb inflationary pressure on the costs of goods and services, which could additionally have the effects of raising the cost of capital and depressing economic growth.
Federal Reserve to increase the federal funds interest rate by 5.25% between March 2022 and December 2023 in an effort to curb inflationary pressure on the costs of goods and services.
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, and have the opportunity to further their professional 10 Table of Contents development through appropriate external educational programs. We offer tuition reimbursement benefits for various extended educational learning opportunities.
We also support employees’ seeking 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 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 support diversity of thought, perspective, sexual orientation, gender, gender identity and expression, race, ethnicity, culture and professional experience, among others.
Our policies and practices are designed to support diversity of thought, perspective, sexual orientation, gender, gender identity and expression, race, ethnicity, culture and professional experience, 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.
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.
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, 2023, we had 38 full time employees. We may hire additional personnel as appropriate.
Some municipalities in Colorado have enacted local rules restricting oil and gas operations ( e.g. , by implementing mandatory setbacks, controlling odors, and requiring further environmental and policy review before fracturing is approved) based on SB 101. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be.
We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be.
In 2021 and 2022, we accelerated our diversification outside the Williston Basin via larger acquisitions, including the acquisition of significant producing natural gas properties in the Appalachian Basin and several acquisitions in the Permian Basin. We have also added to our legacy position in the Williston Basin via larger acquisitions.
Since then we have significantly grown and diversified our properties via acquisitions in the Permian Basin and the Appalachian Basin, while also adding to our legacy position in the Williston Basin. See Note 3 to our financial statements for details regarding our recent acquisitions.
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We strive for financial strength and flexibility through the prudent management of our balance sheet. We intend to use a significant portion of our expected free cash flow in 2023 to reduce our borrowings under our Revolving Credit Facility with the objective of maintaining leverage near our target of 1.0x Debt / Adjusted EBITDA. • Systematic Hedging Strategy.
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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.
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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.
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We have provided stockholder returns in the form of cash dividends and security repurchases, and will seek to grow stockholder returns over time.
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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.
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While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate, which could additionally have the effects of raising the cost of capital and depressing economic growth.
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The EPA is undergoing a two-phase rulemaking process to redefine the definition of WOTUS which could be impacted by the United States Supreme Court’s upcoming decision in Sackett v. EPA , a case regarding the proper test in determining whether wetlands qualify as navigable WOTUS.
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Moreover, the Biden Administration has indicated that it expects to impose additional federal regulations limiting access to and production from federal lands.
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The first rule was finalized by the EPA on December 30, 2022, and the EPA is expected to propose the second rule by November 2023 and issue a final rule by July 2024. Changes in the definition of WOTUS could potentially expand CWA jurisdiction to include more features in areas where oil and gas operations are conducted.
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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.
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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. However, the Colorado legislature subsequently enacted “SB 101” that gave significant local control over oil and gas well head operations.
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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.
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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.
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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.
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Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production.
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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.
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The EPA has also proposed rules in November 2021 and 2022 intended to reduce methane emissions from new and existing oil and gas sources.
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The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply.
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To the extent that our products are competing with higher GHG emitting energy sources, our products would become more desirable in the market with more stringent limitations on GHG emissions.
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At the international level, the United Nations-sponsored Paris Agreement requires signatory countries to set voluntary targets to reduce domestic GHG emissions.
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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 GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
Added
Army Corps of Engineers (the “Corps”) 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.
Removed
The majority of scientific studies on climate change suggest that extreme weather conditions and other risks may occur in the future in the areas where we operate, although the scientific studies are not unanimous.
Added
EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface 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 .
Removed
Although operators may take steps to mitigate any such risks, no assurance can be given that they will not have a material adverse effect on our business. Human Capital Resources As of December 31, 2022, we had 33 full time employees. We may hire additional personnel as appropriate.
Added
However, litigation opposing the September 2023 final rule remains ongoing and 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.
Added
Additionally, in September 2023, the Biden Administration announced that federal 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.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

67 edited+23 added−23 removed273 unchanged
Biggest changeRisks Related to Legal and Regulatory Matters The current presidential administration, acting through the executive branch and/or in coordination with Congress, already has ordered or proposed, and could enact additional rules and regulations that restrict our ability to acquire federal leases in the future and/or impose more onerous permitting and other costly environmental, health and safety requirements.
Biggest changeIn either case, and in other cases, our obligations under the notes and the indenture could increase the cost of acquiring us or otherwise discourage a third party from acquiring us or removing incumbent management, including in a transaction that noteholders or holders of our common stock may view as favorable . 27 Table of Contents Risks Related to Legal and Regulatory Matters The current presidential administration, acting through the executive branch and/or in coordination with Congress, already has ordered or proposed, and could enact additional rules and regulations that restrict our ability to acquire federal leases in the future and/or impose more onerous permitting and other costly environmental, health and safety requirements.
The success and timing of development activities by our operators will depend on a number of factors that will largely be outside of our control, including oil and natural gas prices and other factors generally affecting industry operating environment; the timing and amount of capital expenditures; their expertise and financial resources; approval of other participants in drilling wells; selection of technology; and the rate of production of reserves, if any.
The success and timing of development activities by our operators will depend on a number of factors that will largely be outside of our control, including oil and natural gas prices and other factors generally affecting the industry operating environment; the timing and amount of capital expenditures; their expertise and financial resources; approval of other participants in drilling wells; selection of technology; and the rate of production of reserves, if any.
Any acquisition involves other potential risks, including, among other things: • the validity of our assumptions about reserves, future production, revenues and costs; • a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions; • a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; • the ultimate value of any contingent consideration agreed to be paid in an acquisition; • dilution to stockholders if we use equity as consideration for, or to finance, acquisitions; 18 Table of Contents • the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; • an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and • an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.
Any acquisition involves other potential risks, including, among other things: • the validity of our assumptions about reserves, future production, revenues and costs; • a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions; • a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; • the ultimate value of any contingent consideration agreed to be paid in an acquisition; • dilution to stockholders if we use equity as consideration for, or to finance, acquisitions; • the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; • an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and • an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.
If our operators are not successful in the development, exploitation, production and exploration activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected. 16 Table of Contents These risks are heightened in a low commodity price environment, which may present significant challenges to our operators.
If our operators are not successful in the development, exploitation, production and exploration activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected. 17 Table of Contents These risks are heightened in a low commodity price environment, which may present significant challenges to our operators.
Any significant variance could 14 Table of Contents materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K, subsequent reports we file with the SEC or other company materials. Our future success depends on our ability to replace reserves that our operators produce.
Any significant variance could 15 Table of Contents materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K, subsequent reports we file with the SEC or other company materials. Our future success depends on our ability to replace reserves that our operators produce.
These factors include, but are not limited to, the following: • changes in global supply and demand for oil and natural gas; • the actions of OPEC and other major oil producing countries, such as Russia, relating to oil price and production levels, including announcements of potential changes to such levels; • worldwide and regional economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks including war, terrorism, political unrest, or health epidemics (such as the global COVID-19 coronavirus outbreak); • the price and quantity of imports of foreign oil and natural gas; • the uncertainty in capital and commodities markets and the ability of oil and gas producers to access capital; • increased focus by the investment community on sustainability practices in the oil and natural gas industry; • political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity; • the outbreak of military hostilities, including the ongoing conflict between Russia and Ukraine and the destabilizing effect such conflict continues to pose for the European continent or the global oil and natural gas markets; • the level of global oil and natural gas exploration, production activity and inventories; • changes in U.S. energy policy; • weather conditions, chronic and acute climatic events associated with the effects of global climate change, and outbreak of disease; • technological advances affecting energy consumption; • the development, exploitation and market acceptance of alternative energy sources as part of a transition to a lower carbon economy; • domestic and foreign governmental taxes, tariffs and/or regulations; • proximity and capacity of oil and natural gas pipelines and other transportation facilities; • the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and • the price and availability of alternative fuels.
These factors include, but are not limited to, the following: • changes in global supply and demand for oil and natural gas; • the actions of OPEC and other major oil producing countries, such as Russia, relating to oil price and production levels, including announcements of potential changes to such levels; • worldwide and regional economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks including war, terrorism, political unrest, or health epidemics; • the price and quantity of imports of foreign oil and natural gas; • the uncertainty in capital and commodities markets and the ability of oil and gas producers to access capital; • increased focus by the investment community on sustainability practices in the oil and natural gas industry; • political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity; • the outbreak of military hostilities, including the ongoing conflict between Russia and Ukraine and the destabilizing effect such conflict continues to pose for the European continent or the global oil and natural gas markets, as well as the ongoing conflict in Israel and the surrounding region; • the level of global oil and natural gas exploration, production activity and inventories; • changes in U.S. energy policy; • weather conditions, chronic and acute climatic events associated with the effects of global climate change, and outbreak of disease; • technological advances affecting energy consumption; • the development, exploitation and market acceptance of alternative energy sources as part of a transition to a lower carbon economy; • domestic and foreign governmental taxes, tariffs and/or regulations; • proximity and capacity of oil and natural gas pipelines and other transportation facilities; • the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and • the price and availability of alternative fuels.
Finally, our ability to pay dividends to our stockholders may be limited by covenants in any debt agreements that we are currently a party to, including our Revolving Credit Facility and the Senior Notes Indenture, or may enter into in the future.
Finally, our ability to pay dividends to our stockholders may be limited by covenants in any debt agreements that we are currently a party to, including our Revolving Credit Facility and the Senior Notes Indentures, or may enter into in the future.
The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could 28 Table of Contents eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
The key areas in respect of which we face competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational purposes; purchasing, leasing, hiring, chartering or other procuring of equipment by our operators that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals.
The key areas in respect of which we face competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational 20 Table of Contents purposes; purchasing, leasing, hiring, chartering or other procuring of equipment by our operators that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals.
The discharge of oil, natural gas or other 30 Table of Contents pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge, regardless of whether we were responsible for the release or contamination and regardless of whether our operating partners met previous standards in the industry at the time they were conducted.
The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge, regardless of whether we were responsible for the release or contamination and regardless of whether our operating partners met previous standards in the industry at the time they were conducted.
In addition, upon a default or other failure to perform, or a termination of obligations, by an option counterparty, we may suffer adverse tax consequences and more dilution than we currently anticipate with respect to our common stock. We can provide no assurances as to the financial stability or viability of any option counterparty.
In addition, upon a default or other failure to perform, or a termination of obligations, by an option counterparty, we may 26 Table of Contents suffer adverse tax consequences and more dilution than we currently anticipate with respect to our common stock. We can provide no assurances as to the financial stability or viability of any option counterparty.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is used extensively by our third-party operating partners.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. 31 Table of Contents Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is used extensively by our third-party operating partners.
In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations. Our business plan requires significant capital expenditures, which we may be unable to obtain on favorable terms or at all. Our exploration, development and acquisition activities require substantial capital expenditures.
In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations. 25 Table of Contents Our business plan requires significant capital expenditures, which we may be unable to obtain on favorable terms or at all. Our exploration, development and acquisition activities require substantial capital expenditures.
The capped call 25 Table of Contents transactions are expected generally to reduce the potential dilution to our common stock upon any conversion of the Convertible Notes and/or offset any potential cash payments we are required to make in excess of the principal amount of converted notes, as the case may be, with such reduction and/or offset subject to a cap.
The capped call transactions are expected generally to reduce the potential dilution to our common stock upon any conversion of the Convertible Notes and/or offset any potential cash payments we are required to make in excess of the principal amount of converted notes, as the case may be, with such reduction and/or offset subject to a cap.
We describe these and other risks in much greater detail below. 12 Table of Contents Risks Related to Our Business and the Oil, Natural Gas and NGL Industry Oil and natural gas prices are volatile.
We describe these and other risks in much greater detail below. 13 Table of Contents Risks Related to Our Business and the Oil, Natural Gas and NGL Industry Oil and natural gas prices are volatile.
Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies.
Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to 19 Table of Contents provide effective contractual protection against all or a portion of the underlying deficiencies.
If we were to lose members of our 19 Table of Contents management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed. Deficiencies of title to our leased interests could significantly affect our financial condition.
If we were to lose members of our management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed. Deficiencies of title to our leased interests could significantly affect our financial condition.
Further, under the if-converted method, the dilutive shares are computed assuming the maximum dilutive 26 Table of Contents impact. We cannot be sure that we will be able to continue to demonstrate the ability to settle the Convertible Notes in cash or that the accounting standards will continue to permit the use of the if-converted method.
Further, under the if-converted method, the dilutive shares are computed assuming the maximum dilutive impact. We cannot be sure that we will be able to continue to demonstrate the ability to settle the Convertible Notes in cash or that the accounting standards will continue to permit the use of the if-converted method.
In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled by our operators as a result of other factors, including: • declines in oil or natural gas prices, as occurred in 2020 in connection with the COVID-19 pandemic; 13 Table of Contents • infrastructure limitations, such as the gas gathering and processing constraints experienced in the Williston Basin in 2019; • the high cost, shortages or delays of equipment, materials and services; • unexpected operational events, pipeline ruptures or spills, adverse weather conditions, facility malfunctions or title problems; • compliance with environmental and other governmental requirements; • regulations, restrictions, moratoria and bans on hydraulic fracturing; • unusual or unexpected geological formations; • environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas; • fires, blowouts, craterings and explosions; • uncontrollable flows of oil, natural gas or well fluids; and • pipeline capacity curtailments.
In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled by our operators as a result of other factors, including: • declines in oil or natural gas prices; 14 Table of Contents • infrastructure limitations, such as the gas gathering and processing constraints experienced in the Williston Basin in 2019; • the high cost, shortages or delays of equipment, materials and services; • unexpected operational events, pipeline ruptures or spills, adverse weather conditions, facility malfunctions or title problems; • compliance with environmental and other governmental requirements; • regulations, restrictions, moratoria and bans on hydraulic fracturing; • unusual or unexpected geological formations; • environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas; • fires, blowouts, craterings and explosions; • uncontrollable flows of oil, natural gas or well fluids; and • pipeline capacity curtailments.
In addition, future issuances of common stock under our 2018 Equity Incentive Plan or other equity incentive plans that we may adopt in the future, or in connection with an acquisition or otherwise, would also dilute the percentage ownership held by our stockholders.
In addition, future issuances of common stock under our Amended and Restated 2018 Equity Incentive Plan or other equity incentive plans that we may adopt in the future, or in connection with an acquisition or otherwise, would also dilute the percentage ownership held by our stockholders.
Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt.
Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial 24 Table of Contents performance, and, as a result, our ability to generate cash flow from operations and to pay our debt.
In addition, certain 28 Table of Contents exceptions apply to the excise tax. On December 27, 2022, the U.S. Department of the Treasury (the “Treasury”) issued a notice that it intends to publish proposed regulations addressing the application of the excise tax (the “Notice”).
In addition, certain exceptions apply to the excise tax. On December 27, 2022, the U.S. Department of the Treasury (the “Treasury”) issued a notice that it intends to publish proposed regulations addressing the application of the excise tax (the “Notice”).
In addition, in November 2021, the EPA proposed a new rule that would impose more stringent methane emissions standards for new and modified sources in the oil and gas industry, and to regulate existing sources in the oil and gas industry for the first time.
In addition, in November 2021, the EPA proposed a new rule that would impose more stringent methane emissions standards for new and modified sources in the oil and gas industry, and to regulate existing sources in the oil and gas industry for the first time. In November, 2022, the EPA issued the proposed rule supplementing the November 2021 proposed rule.
Approximately 35% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2022. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate.
Approximately 31% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2023. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate.
We in certain circumstances could determine in our discretion that it is not feasible or practical to implement or complete certain of our ESG goals, initiatives, policies or procedures based on cost, timing or other considerations.
We may determine in our discretion that it is not feasible or practical to implement or complete certain of our ESG goals, initiatives, policies or procedures based on cost, timing or other considerations.
Accordingly, our business and operations, and those of our operating partners, are subject to executive, regulatory, political and 21 Table of Contents financial risks associated with oil and natural gas services and products and the emission of GHGs.
Accordingly, our business and operations, and those of our operating partners, are subject to executive, regulatory, political and financial risks associated with oil and natural gas services and products and the emission of GHGs.
As a result of 20 Table of Contents these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.
As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.
We maintain an active hedging program related to commodity price risks. Such legislation and regulations could reduce trading positions and the market-making activities of our counterparties.
We maintain an active hedging program related to commodity price risks. 30 Table of Contents Such legislation and regulations could reduce trading positions and the market-making activities of our counterparties.
Our ability to declare and pay dividends to our stockholders is subject to certain laws, regulations, and policies, including minimum capital requirements and, as a Delaware 24 Table of Contents corporation, we are subject to certain restrictions on dividends under the DGCL.
Our ability to declare and pay dividends to our stockholders is subject to certain laws, regulations, and policies, including minimum capital requirements and, as a Delaware corporation, we are subject to certain restrictions on dividends under the DGCL.
Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.
Although we utilize various procedures and controls to monitor these 21 Table of Contents threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.
Provisions in the Convertible Notes Indenture (as defined below) could delay or prevent an otherwise beneficial takeover of us. Certain provisions in the Convertible Notes Indenture could make a third-party attempt to acquire us more difficult or expensive.
Provisions in the indenture governing the Convertible Notes could delay or prevent an otherwise beneficial takeover of us. Certain provisions in the indenture governing the Convertible Notes could make a third-party attempt to acquire us more difficult or expensive.
Our ability to pay dividends to our stockholders is restricted by applicable laws and regulations and requirements under certain of our debt agreements, including our Revolving Credit Facility and the Senior Notes (as defined below).
Our ability to pay dividends to our stockholders is restricted by applicable laws and regulations and requirements under certain of our debt agreements, including our Revolving Credit Facility and the Senior Notes Indentures.
If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.
If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. We may be able to incur substantially more debt.
Our Revolving Credit Facility, the indenture governing our Senior Notes due 2028 (the “Senior Notes Indenture”), and any future indebtedness we incur may contain a number of restrictive covenants that will impose significant operating and 23 Table of Contents financial restrictions on us, including restrictions on our ability to, among other things: declare or pay any dividend or make any other distributions on, purchase or redeem our equity interests or purchase or redeem certain debt; make loans or certain investments; make certain acquisitions and investments; incur or guarantee additional indebtedness or issue certain types of equity securities; incur liens; transfer or sell assets; create subsidiaries; consolidate, merge or transfer all or substantially all of our assets; and engage in transactions with our affiliates.
Our Revolving Credit Facility, the indenture the “2028 Notes Indenture” governing our 8.125% senior notes due 2028 (the “Senior Notes due 2028”), and the indenture the “2031 Notes Indenture” and, together with the 2028 Notes Indenture, the “Senior Notes Indentures”) governing our 8.750% senior notes due 2031 (the “Senior Notes due 2031” and, together with the Senior Notes due 2028, the “Senior Notes”), and any future indebtedness we incur may contain a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things: declare or pay any dividend or make any other distributions on, purchase or redeem our equity interests or purchase or redeem certain debt; make loans or certain investments; make certain acquisitions and investments; incur or guarantee additional indebtedness or issue certain types of equity securities; incur liens; transfer or sell assets; create subsidiaries; consolidate, merge or transfer all or substantially all of our assets; and engage in transactions with our affiliates.
Many scientists have concluded that increasing concentrations of GHG in the earth’s atmosphere may produce significant physical effects, such as increased frequency and severity of storms, droughts and floods, among other climatic phenomena.
Most scientists have concluded that increasing concentrations of GHG in the earth’s atmosphere may produce significant physical effects on weather conditions, such as increased frequency and severity of storms, extreme temperatures, droughts and floods, among other climatic phenomena.
Holders of our common stock are only entitled to receive such cash dividends as our board of directors, in its sole discretion, may declare out of funds legally available for such payments. On May 6, 2021, our board of directors declared our first cash dividend on our common stock in the amount of $0.03 per share.
Holders of our common stock are only entitled to receive such cash dividends as our board of directors, in its sole discretion, may declare out of funds legally available for such payments. On August 1, 2023, our board of directors declared a cash dividend on our common stock in the amount of $0.38 per share.
The capped call transactions may affect the value of the Convertible Notes and our common stock. In connection with the pricing of the Convertible Notes, we entered into privately negotiated capped call transactions relating to such notes with the option counterparties.
The capped call transactions may affect the value of the Convertible Notes and our common stock. In connection with the pricing of our 3.625% convertible senior notes due 2029 (the “Convertible Notes”), we entered into privately negotiated capped call transactions relating to such notes with the option counterparties.
Derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable liquids.
A portion of our crude oil production is transported to market centers by rail. Derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable liquids.
Covenants contained in the instruments governing our indebtedness restrict the payment of dividends. Investors may be forced to rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.
Covenants contained in the instruments governing our indebtedness restrict the payment of dividends. Investors may be forced to rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. 33 Table of Contents Item 1B. Unresolved Staff Comments None.
In July 2020, a federal district court ordered DAPL to be shut down pending the completion of an environmental impact statement (“EIS”) to determine whether the 15 Table of Contents DAPL poses a threat to the Missouri River and drinking water supply of the Standing Rock Sioux Reservation. DAPL currently remains in operation while the U.S.
In July 2020, a federal district court ordered DAPL to be shut down pending the completion of an environmental impact statement (“EIS”) to determine whether the 16 Table of Contents DAPL poses a threat to the Missouri River and drinking water supply of the Standing Rock Sioux Reservation. The temporary shutdown order was overturned by the U.S.
Additionally, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks and opportunities, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies. We cannot predict the costs of implementation or any potential adverse impacts resulting from the rulemaking.
Additionally, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks and opportunities, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies.
Increasing attention to climate change, for example, may result in demand shifts for natural gas and oil products, additional governmental investigations, private litigation against us, operational delays or restrictions, increased operating costs, and additional regulatory burdens.
Increasing attention to climate change may also result in additional governmental investigations, private litigation against us, operational delays or restrictions, increased operating costs, and additional regulatory burdens.
The ultimate effect of these rules and any additional regulations on our business is uncertain. 29 Table of Contents The full impact of the Dodd-Frank Act and related regulatory requirements on our business will not be known until the regulations are fully implemented and the market for derivatives contracts has adjusted.
The full impact of the Dodd-Frank Act and related regulatory requirements on our business will not be known until the regulations are fully implemented and the market for derivatives contracts has adjusted.
Our certificate of incorporation authorizes us to issue 135,000,000 shares of common stock, of which 85,165,807 shares were issued and outstanding as of December 31, 2022.
Our certificate of incorporation authorizes us to issue 135,000,000 shares of common stock, of which 100,761,148 shares were issued and outstanding as of December 31, 2023.
If our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions.
If our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions. The ultimate effect of these rules and any additional regulations on our business is uncertain.
The physical effects of adverse weather conditions, such as increased frequency and severity of droughts, storms, floods and other climatic events, could adversely affect or delay demand for oil and natural gas products or cause us or our third party operators to incur significant costs in preparing for, or responding to, the effects of climatic events themselves, which may not be fully insured.
If any such effects were to occur, they could adversely affect or delay demand for oil and natural gas products or cause us or our third party operators to incur significant costs in preparing for, or responding to, the effects of climatic events themselves, which may not be fully insured.
As a non-operator, our development of successful operations relies extensively on third parties, which could have a material adverse effect on our results of operation. We have only participated in wells operated by third parties. The success of our business operations depends on the timing of drilling activities and success of our third-party operators.
Any of these effects could have an adverse effect on our business, results of operations and financial condition. As a non-operator, our development of successful operations relies extensively on third parties, which could have a material adverse effect on our results of operation. We have only participated in wells operated by third parties.
With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers.
With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. 22 Table of Contents This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.
Department of the Interior (“DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program.
Department of the Interior (“DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed subject to certain limitations.
Financial institutions may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations.
Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations.
Any of these executive, administrative or Congressional actions could adversely affect our financial condition and results of operations by restricting the lands available for development and/or access to permits required for such development, or by imposing additional and costly environmental, health and safety requirements. 27 Table of Contents Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations.
Any of these executive, administrative or Congressional actions could adversely affect our financial condition and results of operations by restricting the lands available for development and/or access to permits required for such development, or by imposing additional and costly environmental, health and safety requirements.
In situations where cost inflation exceeds commodity price inflation, our profitability and cash flow, and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash flows.
In situations where cost inflation exceeds commodity price inflation, our profitability and cash flow, and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted.
In general, under Section 382 of the Internal Revenue Code of 1986, as amended (the “IRC”), a corporation that undergoes an “ownership change” can be subject to limitations on the use of its NOLs to offset future taxable income.
At December 31, 2023, we had an estimated NOL carryforward of approximately $573.0 million for U.S. federal income tax purposes. In general, under Section 382 of the Internal Revenue Code of 1986, as amended (the “IRC”), a corporation that undergoes an “ownership change” can be subject to limitations on the use of its NOLs to offset future taxable income.
Business—Governmental Regulation and Environmental Matters” and “—Climate Change” for a further discussion of the laws and regulations related to GHGs and of climate change. 31 Table of Contents Risks Related to Our Common Stock There may be future sales or issuances of our common stock, including issuances in connection with our incentive plans, acquisitions or otherwise, which will dilute the ownership interests of stockholders and may adversely affect the market price of our common stock.
Risks Related to Our Common Stock There may be future sales or issuances of our common stock, including issuances in connection with our incentive plans, acquisitions or otherwise, which will dilute the ownership interests of stockholders and may adversely affect the market price of our common stock.
We may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our Revolving Credit Facility, the Senior Notes and under any future debt agreements. If new debt is added to our current debt levels, the related risks that we now face could increase.
This could further exacerbate the risks associated with our substantial indebtedness. We may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our Revolving Credit Facility, the Senior Notes Indentures and under any future debt agreements.
As of December 31, 2022, we estimate that we had leases that were not developed that represented 7,402 net acres potentially expiring in 2023, 7,895 net acres potentially expiring in 2024, 5,522 net acres potentially expiring in 2025, 726 net acres potentially expiring in 2026, and 4,530 net acres potentially expiring in 2026 and beyond.
As of December 31, 2023, we estimate that we had leases that were not developed that represented 8,442 net acres potentially expiring in 2024, 5,896 net acres potentially expiring in 2025, 1,595 net acres potentially expiring in 2026, 1,746 net acres potentially expiring in 2027, and 7,571 net acres potentially expiring in 2028 and beyond.
Our business involves the selling and shipping by rail of crude oil, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations. A portion of our crude oil production is transported to market centers by rail.
The excise tax would cause a reduction in our cash available on hand, which could have a negative impact on our business and operations. 29 Table of Contents Our business involves the selling and shipping by rail of crude oil, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.
To the extent the frequency of extreme weather events increases, this could impact our business in various ways, including damage to operators’ facilities at our properties or increased insurance premiums. Any of these effects could have an adverse effect on our business, results of operations and financial condition.
To the extent the frequency of extreme weather events increases, this could impact our business in various ways, including damage to operators’ facilities at our properties or increased insurance premiums. Potential adverse effects on our third party operators could also include disruption of their production activities and supply chain.
Negative public perception could cause the permits our operating partners need to conduct their operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business. 22 Table of Contents Further, failure or a perception (whether or not valid) of failure to implement our ESG strategy or achieve sustainability goals we have set could damage our reputation, causing our investors or other stakeholders to lose confidence in our company, and negatively impact our operations.
Failure or a perception (whether or not valid) of failure to implement our ESG strategy or achieve sustainability goals we have set could damage our reputation, causing our investors or other stakeholders to lose confidence in our company, and negatively impact our operations.
Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA is currently expected to issue a final rule by August 2023.
Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” In December 2023, the EPA announced a final rule, 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.
Such ratings are used by some investors to inform their investment and voting decisions and thus unfavorable ESG ratings could have a negative impact on our stock price and our access to and costs of capital.
Such ratings are used by some investors to inform their investment and voting decisions and thus unfavorable ESG ratings could have a negative impact on our stock price and our access to and costs of capital. 23 Table of Contents Risks Related to Our Financing and Indebtedness Any significant reduction in our borrowing base under our Revolving Credit Facility will negatively impact our liquidity and could adversely affect our business and financial results.
Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations.
This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations.
Any of these outcomes could have a material adverse effect on our business, operations, financial results and liquidity The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash flows. 18 Table of Contents The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
We have net operating loss (“NOL”) carryforwards that we may use to offset against taxable income for U.S. federal income tax purposes. At December 31, 2022, we had an estimated NOL carryforward of approximately $520.7 million for U.S. federal income tax purposes.
Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations. We have net operating loss (“NOL”) carryforwards that we may use to offset against taxable income for U.S. federal income tax purposes.
In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed subject to certain limitations, although litigation over the leasing pause remains ongoing. As a result, it is difficult to predict if and when such areas may be made available for future exploration activities.
As a result, it is difficult to predict if and when such areas may be made available for future exploration activities.
Federal Reserve and other central banks to increase interest rates multiple times in 2022 in an effort to curb inflationary pressure on the costs of goods and services, which could have the effects of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business.
While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate, which could additionally have the effects of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business.
The dividend was paid on July 30, 2021 to stockholders of record as of the close of business on June 30, 2021.
The dividend was paid on October 31, 2023 to stockholders of record as of the close of business on September 28, 2023. On October 30, 2023, our board of directors declared a cash dividend on our common stock in the amount of $0.40 per share.
Removed
Army Corps of Engineers (“USACE”) conducts the review, which is currently anticipated to be completed in the spring of 2023. In addition, on September 20, 2021, the owner of DAPL filed a petition with the U.S. Supreme Court seeking review of the lower courts’ decisions requiring a new EIS and permit, which was denied in February 2022.
Added
Court of Appeals in August 2020. DAPL currently remains in operation while the U.S. Army Corps of Engineers (“USACE”) conducts the EIS, which was released in draft form in September 2023 and was open for public comment until mid-December 2023. The date that the final EIS will be published is not yet known.
Removed
The COVID-19 pandemic had, and events beyond our control, including a global or domestic health crisis, may have, a material adverse effect on our financial condition and results of operations. 17 Table of Contents We face risks related to public health crises, including the COVID-19 pandemic.
Added
The success of our business operations depends on the timing of drilling activities and success of our third-party operators.
Removed
The effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity in 2020.
Added
Federal Reserve to increase the federal funds interest rate by 5.25% between March 2022 and December 2023 in an effort to curb inflationary pressure on the costs of goods and services.
Removed
The collapse in the demand for oil caused by this unprecedented global health and economic crisis contributed to the significant decrease in crude oil prices in 2020 and had a material adverse impact on our financial condition and results of operations. Since the beginning of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded.
Added
Financial institutions may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector.
Removed
However, we continue to monitor the effects of the pandemic on our operations. The impact of any new, more contagious or harmful COVID-19 variants that may emerge, and the effectiveness of COVID-19 vaccines against variants and the related responses by governments, including reinstated government-imposed lockdowns or other measures, cannot be predicted at this time.
Added
Negative public perception in relation to climate change or other environmental matters could cause the permits our operating partners need to conduct their operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.
Removed
Both the health and economic aspects of the COVID-19 pandemic remain highly fluid and the future course of each is uncertain.
Added
The dividend was paid on January 31, 2024 to stockholders of record as of the close of business on December 28, 2023. On February 5, 2024, our board of directors declared a cash dividend on our common stock in the amount of $0.40 per share.
Removed
We cannot foresee whether the outbreak of COVID-19 will be effectively contained on a sustained basis, nor can we predict the severity and duration of its impact or the occurrence of other events beyond our control, including other potential global or domestic health crisis.

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Item 2. Properties

Properties — owned and leased real estate

53 edited+6 added−3 removed39 unchanged
Biggest changeManagement’s Discussion and Analysis of Financial Condition and Results of Operations.” 38 Table of Contents Years Ended December 31, 2022 2021 2020 Net Production: Oil (Bbl) 16,090,072 12,288,358 9,361,138 Natural Gas and NGLs (Mcf) 68,829,142 44,073,941 16,473,287 Total (Boe) 27,561,596 19,634,015 12,106,686 Oil (Bbl) per day 44,082 33,667 25,577 Mcf per day 188,573 120,751 45,009 Total (Boe) per day 75,511 53,792 33,078 Average Sales Prices: Oil (per Bbl) $ 91.65 $ 62.94 $ 32.61 Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl) (22.05) (10.17) 20.08 Oil Net of Settled Oil Derivatives (per Bbl) 69.60 52.77 52.69 Natural Gas and NGLs (per Mcf) 7.43 4.57 1.14 Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) (1.60) (0.92) 0.02 Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 5.83 3.65 1.16 Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 72.05 49.66 26.77 Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) (16.52) (8.45) 15.55 Realized Price on a Boe Basis Including Settled Commodity Derivatives 55.53 41.21 42.32 Average Costs: Production Expenses (per Boe) $ 9.46 $ 8.70 $ 9.61 Drilling and Development Activity The following table sets forth the number of gross and net productive and non-productive wells drilled in the years ended December 31, 2022, 2021 and 2020.
Biggest changeManagement’s Discussion and Analysis of Financial Condition and Results of Operations.” 40 Table of Contents Year Ended December 31, 2023 2022 2021 Net Production: Oil (Bbl) 22,012,986 16,090,072 12,288,358 Natural Gas and NGLs (Mcf) 84,341,858 68,829,142 44,073,941 Total (Boe) 36,069,962 27,561,596 19,634,015 Oil (Bbl) per day 60,310 44,082 33,667 Mcf per day 231,074 188,573 120,751 Total (Boe) per day 98,822 75,511 53,792 Average Sales Prices: Oil (per Bbl) $ 74.78 $ 91.65 $ 62.94 Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) (0.90) (21.48) (10.19) Oil Net of Settled Oil Derivatives (per Bbl) 73.88 70.17 52.75 Natural Gas and NGLs (per Mcf) 2.98 7.43 4.57 Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.92 (1.60) (0.92) Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 3.90 5.83 3.65 Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 52.61 72.05 49.66 Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) 1.61 (16.52) (6.37) Realized Price on a Boe Basis Including Settled Commodity Derivatives 54.22 55.53 43.29 Average Costs: Production Expenses (per Boe) $ 9.62 $ 9.46 $ 8.70 41 Table of Contents The following table sets forth our production results for the years ended December 31, 2023, 2022 and 2021 in total and for each of our basins of operations.
Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, after adjustment to reflect applicable transportation and quality differentials.
Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, after adjustment to reflect applicable transportation and quality differentials.
Cawley is a reservoir-evaluation consulting firm who evaluates oil and natural gas properties and independently certifies petroleum reserves quantities for various clients throughout the United States. Cawley has substantial experience calculating the reserves of various other companies and, as such, we believe Cawley has sufficient experience to appropriately audit our reserves.
Cawley is a reservoir-evaluation consulting firm who evaluates oil and natural gas properties and independently certifies petroleum reserves quantities for various clients throughout the United States. Cawley has substantial experience auditing and calculating the reserves of various other companies and, as such, we believe Cawley has sufficient experience to appropriately audit our reserves.
In those instances, we still review each lease on a lease-by-lease basis to ensure that the package as a whole meets our acquisition criteria and drilling expectations. See Note 3 and Note 14 to our financial statements regarding our recent acquisition activity.
In those instances, we still review each lease on a lease-by-lease basis to ensure that the package as a whole meets our acquisition criteria and drilling expectations. See Note 3 to our financial statements regarding our recent acquisition activity.
The development of these reserves is dependent upon a number of factors which include, but are not limited to: financial targets such as drilling within cash flow or reducing debt, drilling of obligatory wells, satisfactory 35 Table of Contents rates of return on proposed drilling projects, and the levels of drilling activities by operators in areas where we hold leasehold interests.
The development of these reserves is dependent upon a number of factors which include, but are not limited to: financial targets such as drilling within cash flow or reducing debt, drilling of obligatory wells, satisfactory rates of return on proposed drilling projects, and the levels of drilling activities by operators in areas where we hold leasehold 37 Table of Contents interests.
Cawley utilizes proprietary technology, systems and data to calculate our reserves commensurate with this experience. Cawley is a Texas Registered Engineering Firm (F-693). Our primary contact at Cawley is Todd Brooker, President. Mr. Brooker is a State of Texas Licensed Professional Engineer (License #83462). He is also a member of the Society of Petroleum Engineers.
Cawley utilizes proprietary technology, systems and data to audit our reserves commensurate with this experience. Cawley is a Texas Registered Engineering Firm (F-693). Our primary contact at Cawley is Todd Brooker, President. Mr. Brooker is a State of Texas Licensed Professional Engineer (License #83462). He is also a member of the Society of Petroleum Engineers.
The reserve data set forth in the Cawley report represents only estimates, and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.
The reserve data set forth in the Company report represents only estimates, and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.
As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2022, our future income taxes were significantly reduced. Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control.
As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2023, our future income taxes were significantly reduced. Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control.
(3) Pre-tax PV10%, or PV-10, may be considered a non-GAAP financial measure. See “Reconciliation of PV-10 to Standardized Measure” above for a reconciliation of the PV-10 of our 2022 SEC case proved reserves to the Standardized Measure. GAAP does not prescribe a corresponding measure for PV-10 of proved reserves based on other than SEC prices.
(3) Pre-tax PV10%, or PV-10, may be considered a non-GAAP financial measure. See “Reconciliation of PV-10 to Standardized Measure” above for a reconciliation of the PV-10 of our 2023 SEC Case proved reserves to the Standardized Measure. GAAP does not prescribe a corresponding measure for PV-10 of proved reserves based on other than SEC prices.
The following table summarizes our cumulative gross and net productive oil and natural gas wells by geographic area within the United States at each of December 31, 2022, 2021 and 2020. Wells are classified as oil or natural gas wells according to the predominant production stream.
The following table summarizes our cumulative gross and net productive oil and natural gas wells by geographic area within the United States at each of December 31, 2023, 2022 and 2021. Wells are classified as oil or natural gas wells according to the predominant production stream.
Item 2. Properties Estimated Net Proved Reserves The table below summarizes our estimated net proved reserves at December 31, 2022 based on reports prepared by the Company for the year ended December 31, 2022 and audited by Cawley, our third-party independent reserve engineers.
Item 2. Properties Estimated Net Proved Reserves The table below summarizes our estimated net proved reserves at December 31, 2023 based on reports prepared by the Company for the year ended December 31, 2023 and audited by Cawley, our third-party independent reserve engineers.
In preparing its reports, the Company evaluated properties representing all of our proved reserves at December 31, 2022 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.
In preparing its reports, the Company evaluated properties representing all of our proved reserves at December 31, 2023 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.
All of our proved reserves are located in the United States. 40 Table of Contents Recent Acquisitions We generally assess acreage subject to near-term drilling activities on a lease-by-lease basis because we believe each lease’s contribution to a subject spacing unit is best assessed on that basis if development timing is sufficiently clear.
All of our proved reserves are located in the United States. Recent Acquisitions We generally assess acreage subject to near-term drilling activities on a lease-by-lease basis because we believe each lease’s contribution to a subject spacing unit is best assessed on that basis if development timing is sufficiently clear.
Increased development activity in 2022 led to an increase in our capital spending as well as an increase in the number of undeveloped drilling locations reflected in our 2022 proved reserve estimates.
Increased development activity in 2023 led to an increase in our capital spending as well as an increase in the number of undeveloped drilling locations reflected in our 2023 proved reserve estimates.
In this sensitivity scenario, all operating cost assumptions and other factors, other than the commodity price assumptions, have been held constant with the 2022 SEC case. However, the lower pricing in the sensitivity scenario did result in fewer future drilling locations that were economic at the $70 Flat Case compared to the 2022 SEC case.
In this sensitivity scenario, all operating cost assumptions and other factors, other than the commodity price assumptions, have been held constant with the 2023 SEC Case. However, the change in pricing in the sensitivity scenario did result in fewer future drilling locations that were economic at the $70 Flat Case compared to the 2023 SEC Case.
Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion. We assess all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value.
Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion. 44 Table of Contents We assess all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value.
Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves. 34 Table of Contents The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2022 to the Standardized Measure of discounted future net cash flows.
Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves. 36 Table of Contents The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2023 to the Standardized Measure of discounted future net cash flows.
As a non-operator, we have limited control over the drilling of new wells and primarily rely on our third-party operating partners in this regard. The following table summarizes our total net commitments as of December 31, 2022. (in Bcf) Commitment Volumes 2023 19.0 2024 18.4 2025 3.2 Total 40.6
As a non-operator, we have limited control over the drilling of new wells and primarily rely on our third-party operating partners in this regard. The following table summarizes our total net commitments as of December 31, 2023. (in Bcf) Commitment Volumes 2024 18.4 2025 3.2 Total 21.6
All locations comprising our remaining proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with our development plan. At December 31, 2022, the PV-10 value of our proved undeveloped reserves amounted to 29% of the PV-10 value of our total proved reserves.
All locations comprising our remaining proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with our development plan. At December 31, 2023, the PV-10 value of our proved undeveloped reserves amounted to 20% of the PV-10 value of our total proved reserves.
We have chosen to compare our proved reserves from the 2022 SEC case to one alternate pricing case, which uses a flat pricing deck of $70.00 per Bbl for oil and $3.00 per MMbtu for natural gas (the “$70 Flat Case”). The sensitivity scenario was not audited by a third-party.
We have chosen to compare our proved reserves calculated using SEC Pricing (the “2023 SEC Case”) to one alternate pricing case, which uses a flat pricing deck of $70.00 per Bbl for oil and $3.00 per MMbtu for natural gas (the “$70 Flat Case”). The sensitivity scenario was not audited by a third-party.
Although our 2022 producing property additions exceeded our 5-year average development plan, there are numerous uncertainties.
Although our 2023 producing property additions exceeded our 5-year average development plan, there are numerous uncertainties.
The table below shows our proved reserves utilizing the 2022 SEC case compared with the $70 Flat Case.
The table below shows our proved reserves utilizing the 2023 SEC Case compared with the $70 Flat Case.
Additional discussion of our proved reserves is set forth under the heading “Supplemental Oil and Gas Information - Unaudited” to our financial statements included later in this report. Proved Undeveloped Reserves At December 31, 2022, we had approximately 116.2 MMBoe of proved undeveloped reserves as compared to 117.1 MMBoe at December 31, 2021.
Additional discussion of our proved reserves is set forth under the heading “Supplemental Oil and Gas Information - Unaudited” to our financial statements included later in this report. Proved Undeveloped Reserves At December 31, 2023, we had approximately 104.8 MMBoe of proved undeveloped reserves as compared to 116.2 MMBoe at December 31, 2022.
The reserves set forth in the Cawley report for the properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy.
The reserves set forth in the Company report audited by Cawley for the properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data.
During 2022, we increased our development capital spending by 100% compared to 2021. With 69% of the PV-10 value of our total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to execute our development plan.
During 2023, we increased our capital spending by 31% compared to 2022. With 78% of the PV-10 value of our total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to execute our development plan.
As a result, the $70 Flat Case included 3.0 fewer proved undeveloped net wells compared to the 137.1 proved undeveloped net wells included in the 2022 SEC case. This sensitivity is only meant to demonstrate the impact that changing commodity prices may have on estimated proved reserves and PV-10 and there is no assurance this outcome will be realized.
As a result, the $70 Flat Case included 7.9 fewer proved undeveloped net wells compared to the 146.0 proved undeveloped net wells included in the 2023 SEC Case. This sensitivity is only meant to demonstrate the impact that changing commodity prices may have on estimated proved reserves and PV-10 and there is no assurance this outcome will be realized.
Additionally, our proved undeveloped reserves at December 31, 2022 included 59.3 MMBoe for net wells that had commenced drilling activities but remained classified as undeveloped reserves due to Cawley’s internal guidelines which require greater than 50% of the total costs to have been incurred in order to be classified as proved developed (the related development costs incurred at December 31, 2022 were $61.0 million).
Additionally, our proved undeveloped reserves at December 31, 2023 included 58.6 MMBoe for net wells that had commenced drilling activities but remained classified as undeveloped reserves due to Cawley’s internal guidelines which require greater than 50% of the total costs to have been incurred in order to be classified as proved developed (the related development costs incurred at December 31, 2023 were $175.7 million).
Production costs were held constant for the life of the wells. 36 Table of Contents (2) Prices based on $70.00 per Bbl for oil and $3.00 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $68.32 per Bbl for oil and $4.11 per Mcf for natural gas.
Production costs were held constant for the life of the wells. 38 Table of Contents (2) Prices based on $70.00 per Bbl for oil and $3.00 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $67.38 per Bbl for oil and $3.42 per Mcf for natural gas.
Years Ended December 31, (In thousands, except per Boe data) 2022 2021 2020 Depletion of Oil and Natural Gas Properties $ 248,252 $ 138,759 $ 160,643 Depletion Expense (per Boe) 9.01 7.07 13.27 Research and Development We do not anticipate performing any significant research and development under our plan of operation.
Year Ended December 31, (In thousands, except per Boe data) 2023 2022 2021 Depletion of Oil and Natural Gas Properties $ 482,306 $ 248,252 $ 138,759 Depletion Expense (per Boe) 13.37 9.01 7.07 Research and Development We do not anticipate performing any significant research and development under our plan of operation.
Estimated net proved reserves at December 31, 2022 were 330,809 MBoe, a 15% increase from estimated net proved reserves of 287,682 MBoe at December 31, 2021. The increase was primarily due to the impact of our 2022 acquisitions, as well as higher activity levels in 2022 as compared to 2021.
Estimated net proved reserves at December 31, 2023 were 339,694 MBoe, a 3% increase from estimated net proved reserves of 330,809 MBoe at December 31, 2022. The increase was primarily due to the impact of our 2023 acquisitions, as well as higher activity levels in 2023 as compared to 2022.
The unescalated twelve month arithmetic average of the first day of the month posted prices were adjusted for transportation and quality differentials to arrive at prices of $91.95 per Bbl for oil and $7.43 per Mcf for natural gas.
The unescalated twelve month arithmetic average of the first day of the month posted prices were adjusted for transportation and quality differentials to arrive at prices of $75.51 per Bbl for oil and $3.10 per Mcf for natural gas.
Our proved undeveloped locations were increased from 126.5 net wells at December 31, 2021 to 138.2 net wells at December 31, 2022 due to our 2022 acquisitions, higher commodity prices, and increased development activity. We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled including our acreage.
Our proved undeveloped locations were increased from 138.2 net wells at December 31, 2022 to 146.0 net wells at December 31, 2023 due to our 2023 acquisitions and increased development activity. We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled under our acreage.
Proved developed property additions in 2022 also included 11.6 MMBoe from the conversion of previously undeveloped locations that were not booked in our December 31, 2021 proved undeveloped reserves (the related development costs incurred at December 31, 2022 were $212.2 million).
Proved developed property additions in 2023 also included 12.4 MMBoe from the conversion of previously undeveloped locations that were not booked in our December 31, 2022 proved undeveloped reserves (the related development costs incurred at December 31, 2023 were $242.8 million).
December 31, 2022 2021 2020 Gross Net Gross Net Gross Net Williston Basin 7,487 608.0 6,996 571.7 6,633 474.5 Permian Basin 818 92.8 83 11.6 7 0.6 Appalachian Basin 367 98.5 357 97.5 — — Total 8,672 799.3 7,436 680.8 6,640 475.1 As of December 31, 2022, we had an additional 526 gross (55.4 net) wells in process, meaning wells that have been spud and are in the process of drilling, completing or waiting on completion.
December 31, 2023 2022 2021 Gross Net Gross Net Gross Net Williston Basin 7,981 643.7 7,487 608.0 6,996 571.7 Permian Basin 1,387 207.6 818 92.8 83 11.6 Appalachian Basin 397 100.3 367 98.5 357 97.5 Total 9,765 951.6 8,672 799.3 7,436 680.8 As of December 31, 2023, we had an additional 512 gross (66.5 net) wells in process, meaning wells that have been spud and are in the process of drilling, completing or waiting on completion.
Additionally, we had positive revisions of 0.3 MMBoe primarily due to the aforementioned higher pricing. We also removed 14.3 MMBoe of proved undeveloped reserves due to the SEC-prescribed 5-year rule. Proved Reserves Sensitivity by Price Scenario The SEC disclosure rules allow for optional reserves sensitivity analysis, such as the sensitivity that oil and natural gas reserves have to price fluctuations.
We also removed 24.9 MMBoe of proved undeveloped reserves due to the SEC-prescribed 5-year rule. Proved Reserves Sensitivity by Price Scenario The SEC disclosure rules allow for optional reserves sensitivity analysis, such as the sensitivity that oil and natural gas reserves have to price fluctuations.
SEC Pricing Proved Reserves (In thousands) Standardized Measure Reconciliation Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) $ 7,902,154 Future Income Taxes, Discounted at 10% (1) (1,465,257) Standardized Measure of Discounted Future Net Cash Flows $ 6,436,897 ____________ (1) The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows.
SEC Pricing Proved Reserves (In thousands) Standardized Measure Reconciliation Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) $ 5,004,082 Future Income Taxes, Discounted at 10% (1) (847,845) Standardized Measure of Discounted Future Net Cash Flows $ 4,156,237 ____________ (1) The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows.
The average resulting price used as of December 31, 2022, after adjustment to reflect applicable transportation and quality differentials, was $91.95 per barrel of oil and $7.43 per Mcf of natural gas.
The average resulting price used as of December 31, 2023, after adjustment to reflect applicable transportation and quality differentials, was $75.51 per barrel of oil and $3.10 per Mcf of natural gas.
At December 31, 2022, we had spent a total of $118.5 million related to the development of proved undeveloped reserves, which resulted in the conversion of 18.1 MMBoe of proved undeveloped reserves as of December 31, 2021 to proved developed reserves as of December 31, 2022.
At December 31, 2023, we had spent a total of $327.8 million related to the development of proved undeveloped reserves, which resulted in the conversion of 27.9 MMBoe of proved undeveloped reserves as of December 31, 2022 to proved developed reserves as of December 31, 2023.
A reconciliation of the change in proved undeveloped reserves during 2022 is as follows: MMBoe Estimated Proved Undeveloped Reserves at 12/31/2021 117.1 Converted to Proved Developed Through Drilling (18.1) Added from Extensions and Discoveries 18.5 Purchases of Minerals in Place 12.7 Removed for 5-Year Rule (14.3) Revisions 0.3 Estimated Proved Undeveloped Reserves at 12/31/2022 116.2 Our future development drilling program includes the drilling of approximately 138.2 proved undeveloped net wells before the end of 2027 at an estimated cost of $1,026 million.
A reconciliation of the change in proved undeveloped reserves during 2023 is as follows: MMBoe Estimated Proved Undeveloped Reserves at 12/31/2022 116.2 Converted to Proved Developed Through Drilling (27.9) Added from Extensions and Discoveries 24.6 Purchases of Minerals in Place 23.4 Removed for 5-Year Rule (24.9) Revisions (6.6) Estimated Proved Undeveloped Reserves at 12/31/2023 104.8 Our future development drilling program includes the drilling of approximately 146.0 proved undeveloped net wells before the end of 2028 at an estimated cost of $1.2 billion.
The estimates of the reserves, future production, and income attributable to properties are prepared using the economic software package Aries for Windows, a copyrighted program of Halliburton.
Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy. The estimates of the reserves, future production, and income attributable to properties are prepared using the economic software package Aries for Windows, a copyrighted program of Halliburton.
Our executive internal reserve engineer has a B.S. in petroleum engineering from Montana Tech, has over seventeen years of oil and gas experience on the reservoir side, and has experience working for large independents on projects and acquisitions.
Our executive internal reserve engineer has a B.S. in petroleum engineering from Montana Tech, has over eighteen years of oil and gas experience on the reservoir side, and has experience working for large independents on projects and acquisitions. In addition, we utilize a third-party reservoir engineering firm as our independent reserves auditor for 100% of our reserves base.
(2) The table above values oil and natural gas reserve quantities as of December 31, 2021, assuming constant realized prices of $62.25 per barrel of oil and $3.37 per Mcf of natural gas.
(2) The table above values oil and natural gas reserve quantities as of December 31, 2022, assuming constant realized prices of $91.95 per barrel of oil and $7.43 per Mcf of natural gas.
Our development plan for drilling proved undeveloped wells calls for the drilling of 85.2 net wells during 2023 (includes 47.0 net wells drilled at December 31, 2022, but classified as proved undeveloped due to Cawley’s internal guidelines which require greater than 50% of total costs to be incurred to be classified as developed), 25.4 net wells during 2024, 16.3 net wells during 2025, 7.0 net wells during 2026, and 4.3 net wells during 2027 for a total of 138.2 net wells.
Our development plan for drilling proved undeveloped wells calls for the drilling of 90.9 net wells during 2024 (includes 55.8 net wells spud at December 31, 2023, but classified as proved undeveloped due to Cawley’s internal guidelines which require greater than 50% of total costs to be incurred to be classified as developed), 19.4 net wells during 2025, 18.7 net wells during 2026, 11.6 net wells during 2027, and 5.4 net wells during 2028 for a total of 146.0 net wells.
The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. 39 Table of Contents December 31, 2022 2021 2020 Gross Net (1) Gross Net (1) Gross Net (1) Exploratory Wells: Oil — — — — — — Natural Gas — — — — — — Non-Productive — — — — — — Development Wells: Oil 550 55.9 354 33.6 285 17.8 Natural Gas 7 0.9 8 2.2 — — Non-Productive — — — — — — Total Productive Exploratory and Development Wells 557 56.8 362 35.8 285 17.8 ______________ (1) Net Well totals in 2022, 2021 and 2020 do not include an additional 66.4, 169.4 and 1.0 net wells, respectively, from acquisitions which were already producing when acquired.
December 31, 2023 2022 2021 Gross Net (1) Gross Net (1) Gross Net (1) Exploratory Wells: Oil — — — — — — Natural Gas — — — — — — Non-Productive — — — — — — Development Wells: Oil 803 76.1 550 55.9 354 33.6 Natural Gas 16 0.5 7 0.9 8 2.2 Non-Productive — — — — — — Total Productive Exploratory and Development Wells 819 76.6 557 56.8 362 35.8 ______________ (1) Net Well totals in 2023, 2022 and 2021 do not include an additional 80.4, 66.4 and 169.4 net wells, respectively, from acquisitions which were already producing when acquired.
December 31, 2022 December 31, 2021 Proved Reserves (MBoe)(1) % of Total Proved Reserves (MBoe)(2) % of Total SEC Proved Reserves: Developed 214,602 65 % 170,598 59 % Undeveloped 116,207 35 117,084 41 Total Proved Properties 330,809 100 % 287,682 100 % ___________________ (1) The table above values oil and natural gas reserve quantities as of December 31, 2022, assuming constant realized prices of $91.95 per barrel of oil and $7.43 per Mcf of natural gas.
December 31, 2023 December 31, 2022 Proved Reserves (MBoe)(1) % of Total Proved Reserves (MBoe)(2) % of Total SEC Proved Reserves: Developed 234,861 69 % 214,602 65 % Undeveloped 104,833 31 % 116,207 35 % Total Proved Properties 339,694 100 % 330,809 100 % ___________________ (1) The table above values oil and natural gas reserve quantities as of December 31, 2023, assuming constant realized prices of $75.51 per barrel of oil and $3.10 per Mcf of natural gas.
The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of our reserves. 41 Table of Contents Depletion of Oil and Natural Gas Properties Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs.
Depletion of Oil and Natural Gas Properties Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses during 2023, 2022 and 2021.
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” 37 Table of Contents Internal Controls Over Reserves Estimation Process We utilize a third-party reservoir engineering firm as our independent reserves auditor for 100% of our reserves base.
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” 39 Table of Contents Internal Controls Over Reserves Estimation Process We employ an internal reserve engineering department which is led by our Chief Technical Officer, who is responsible for overseeing the preparation of our reserves estimates.
As a result of the higher activity levels and our 2022 acquisitions, the number of proved undeveloped wells included in the reserves was increased from 126.5 net wells in 2021 to 138.2 net wells in 2022. 33 Table of Contents The following table sets forth summary information by reserve category with respect to estimated proved reserves at December 31, 2022: SEC Pricing Proved Reserves (1) Reserve Volumes PV-10 (3) Reserve Category Oil (MBbls) Natural Gas (MMcf) Total (MBoe) (2) % Amount (In thousands) % PDP Properties 109,498 604,303 210,215 64 % $ 5,434,411 69 % PDNP Properties 3,128 7,552 4,387 1 % 159,541 2 % PUD Properties 50,115 396,551 116,207 35 % 2,308,202 29 % Total 162,741 1,008,406 330,809 100 % $ 7,902,154 100 % _____ ___________ (1) The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2022, based on average prices of $93.67 per barrel of oil and $6.36 per MMbtu of natural gas.
As a result of the higher activity levels and our 2023 acquisitions, the number of proved undeveloped wells included in the reserves was increased from 138.2 net wells in 2022 to 146.0 net wells in 2023. 35 Table of Contents The following table sets forth summary information by reserve category with respect to estimated proved reserves at December 31, 2023: SEC Pricing Proved Reserves (1) Reserve Volumes PV-10 (3) Reserve Category Oil (MBbls) Natural Gas (MMcf) Total (MBoe) (2) % Amount (In thousands) % PDP Properties 118,634 662,079 228,981 67 % $ 3,899,733 78 % PDNP Properties 3,230 15,899 5,880 2 % 113,577 2 % PUD Properties 48,477 338,138 104,833 31 % 990,772 20 % Total 170,341 1,016,116 339,694 100 % $ 5,004,082 100 % _____ ___________ (1) The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2023, based on average prices of $78.22 per barrel of oil and $2.64 per MMbtu of natural gas.
The 2022 lease expirations carried a cost of $8.7 million. We believe that the expired acreage was not material to our capital deployed. Unproved Properties All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion.
Unproved Properties All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion.
Leasehold Properties As of December 31, 2022, our principal assets included approximately 258,970 net acres located in the United States. The following table summarizes our estimated gross and net developed and undeveloped acreage by geographic area at December 31, 2022.
Leasehold Properties As of December 31, 2023, our principal assets included approximately 272,251 net acres located in the United States.
In 2022, we also added 18.5 MMBoe of proved undeveloped reserves as a result of our acquisition and development activity. The SEC-prescribed commodity prices (after adjustment for transportation, quality and basis differentials) were $29.70 higher per barrel of oil and $4.06 higher per Mcf of natural gas at year-end 2022 as compared to year-end 2021.
The SEC-prescribed commodity prices (after adjustment for transportation, quality and basis differentials) were $16.44 lower per barrel of oil and $4.33 lower per Mcf of natural gas at year-end 2023 as compared to year-end 2022. Additionally, we had negative revisions of 6.6 MMBoe primarily due to the aforementioned lower pricing.
The approximate expiration of our net acres which are subject to expire between 2023 and 2027 and thereafter, are set forth below: Acreage Subject to Expiration Year Ended Gross Net December 31, 2023 40,566 7,402 December 31, 2024 26,872 7,895 December 31, 2025 15,564 5,522 December 31, 2026 3,435 726 December 31, 2027 and thereafter 17,120 4,530 Total 103,557 26,075 During 2022, we had leases expire covering approximately 5,796 net acres.
The approximate expiration of our net acres which are subject to expire between 2024 and 2028 and thereafter, are set forth below: Acreage Subject to Expiration Year Ended Gross Net December 31, 2024 42,286 8,442 December 31, 2025 23,876 5,896 December 31, 2026 9,178 1,595 December 31, 2027 20,784 1,746 December 31, 2028 and thereafter 19,162 7,571 Total 115,286 25,250 During 2023, we had leases expire covering approximately 5,173 net acres.
Price Cases 2022 SEC Case (1) $70 Flat Case (2) Net Proved Reserves (December 31, 2022) Oil (MBbl) Developed 112,626 106,371 Undeveloped 50,115 48,169 Total 162,741 154,540 Natural Gas (MMcf) Developed 611,855 556,600 Undeveloped 396,551 390,799 Total 1,008,406 947,399 Total Proved Reserves (MBOE) 330,809 312,440 Pre-tax PV10% (in thousands) (3) $ 7,902,154 $ 4,482,675 _________________ (1) Represents reserves based on pricing prescribed by the SEC.
Price Cases 2023 SEC Case (1) $70 Flat Case (2) Net Proved Reserves (December 31, 2023) Oil (MBbl) Developed 121,865 118,877 Undeveloped 48,477 45,874 Total 170,342 164,751 Natural Gas (MMcf) Developed 677,978 686,780 Undeveloped 338,138 333,651 Total 1,016,116 1,020,431 Total Proved Reserves (MBOE) 339,694 334,823 Pre-tax PV10% (in thousands) (3) $ 5,004,082 $ 4,438,111 _________________ (1) Represents reserves based on pricing prescribed by the SEC.
Removed
In addition, we employ an internal reserve engineering department which is led by our Executive Vice President and Chief Engineer, who is responsible for overseeing the preparation of our reserves estimates.
Added
In 2023, we also added 24.6 MMBoe of proved undeveloped reserves as a result of our development activity. We added an additional 23.4 MMBoe from our acquisitions.
Removed
Developed Acreage Undeveloped Acreage Total Acreage Gross Net Gross Net Gross Net Williston Basin 594,738 167,326 28,582 14,842 623,320 182,168 Permian Basin 27,673 14,070 2,046 3,546 29,719 17,616 Appalachian Basin 195,055 46,491 81,406 12,695 276,461 59,186 Total: 817,466 227,887 112,034 31,083 929,500 258,970 As of December 31, 2022, approximately 88% of our total acreage was developed.
Added
Year Ended December 31, 2023 2022 2021 Net Production: Oil (Bbl) Williston Basin 12,746,957 11,651,938 11,683,218 Permian Basin 9,266,029 4,438,134 605,140 Appalachian Basin — — — Total 22,012,986 16,090,072 12,288,358 Natural Gas and NGLs (Mcf) Williston Basin 31,102,642 27,027,761 23,186,806 Permian Basin 28,594,041 14,255,738 1,111,673 Appalachian Basin 24,645,175 27,545,643 19,775,462 Total 84,341,858 68,829,142 44,073,941 Crude Oil Equivalents (Boe) Williston Basin 17,930,730 16,156,565 15,547,686 Permian Basin 14,031,702 6,814,090 790,419 Appalachian Basin 4,107,529 4,590,941 3,295,910 Total 36,069,961 27,561,596 19,634,015 42 Table of Contents Drilling and Development Activity The following table sets forth the number of gross and net productive and non-productive wells drilled in the years ended December 31, 2023, 2022 and 2021.
Removed
The following table presents our depletion expenses during 2022, 2021 and 2020.
Added
The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated.
Added
The following table summarizes our estimated gross and net developed and undeveloped acreage by geographic area at December 31, 2023. 43 Table of Contents Developed Acreage Undeveloped Acreage Total Acreage Gross Net Gross Net Gross Net Williston Basin 889,133 166,567 72,862 14,074 961,995 180,641 Permian Basin 169,788 30,513 25,599 6,063 195,387 36,576 Appalachian Basin 195,910 46,473 45,986 8,561 241,896 55,034 Total: 1,254,831 243,553 144,447 28,698 1,399,278 272,251 As of December 31, 2023, approximately 89% of our total acreage was developed.
Added
The 2023 lease expirations carried a cost of $5.2 million. We believe that the expired acreage was not material to our capital deployed. As of December 31, 2023, we estimate that less than 1% of our proved undeveloped reserves were attributable to locations scheduled to be drilled after lease expiration.
Added
The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of our reserves.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

11 edited+3 added−0 removed3 unchanged
Biggest changeRecent Sales of Unregistered Securities None, except to the extent previously included by the Company in a Quarterly Report on Form 10-Q or Current Report on Form 8-K. Dividend Policy On May 6, 2021, our board of directors declared our first cash dividend on our common stock in the amount of $0.03 per share.
Biggest changeThe number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock. 47 Table of Contents Recent Sales of Unregistered Securities None, except to the extent previously included by the Company in a Quarterly Report on Form 10-Q or Current Report on Form 8-K.
Issuer Purchases of Equity Securities The table below sets forth the information with respect to purchases made by or on behalf of the Company, or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act), of our common stock during the quarter ended December 31, 2022.
Issuer Purchases of Equity Securities The table below sets forth the information with respect to purchases made by or on behalf of the Company, or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act), of our common stock during the quarter ended December 31, 2023.
Additionally, covenants contained in our Revolving Credit Facility and Senior Notes Indenture restrict the payment of cash dividends on our common stock (see Note 4 to our financial statements).
Additionally, covenants contained in our Revolving Credit Facility and Senior Notes Indentures restrict the payment of cash dividends on our common stock (see Note 4 to our financial statements).
Most recently, on February 6, 2023, our board of directors declared a cash dividend on our common stock in the amount of $0.34 per share. The dividend is payable on April 28, 2023 to stockholders of record as of the close of business on March 30, 2023.
Most recently, on February 5, 2024, our board of directors declared a cash dividend on our common stock in the amount of $0.40 per share, payable on April 30, 2024 to stockholders of record as of the close of business on March 28, 2024.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market Information Our common stock trades on the New York Stock Exchange under the symbol “NOG.” The closing price for our common stock on February 23, 2023 was $31.80 per share.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market Information Our common stock trades on the New York Stock Exchange under the symbol “NOG.” The closing price for our common stock on February 21, 2024 was $34.89 per share.
The following graph compares the 60-month cumulative total stockholder return on our common stock since December 31, 2017, and the cumulative total returns of Standard & Poor’s 500 Index and the NYSE Arca Oil Index (formerly the AMEX Oil Index) for the same period.
The following graph compares the 60-month cumulative total stockholder return on our common stock since December 31, 2018, and the cumulative total returns of the Standard & Poor’s 500 Index, the XOP and the Arca Index for the same period.
Period Total Number of Shares Purchased(1) Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(2) October 1, 2022 to October 31, 2022 1,006,373 $ 29.81 1,006,373 $ 98.5 million November 1, 2022 to November 30, 2022 — — — 98.5 million December 1, 2022 to December 31, 2022 96,805 31.01 96,805 95.5 million Total 1,103,178 $ 29.92 1,103,178 $ 95.5 million __________________________________ 44 Table of Contents (1) Any shares purchased outside of publicly announced plans or programs represent shares surrendered in satisfaction of tax withholding obligations in connection with the vesting of restricted stock awards.
Period Total Number of Shares Purchased(1) Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(2) October 1, 2023 to October 31, 2023 — $ — — $ 87.5 million November 1, 2023 to November 30, 2023 — — — 87.5 million December 1, 2023 to December 31, 2023 — — — 87.5 million Total — $ — — $ 87.5 million __________________________________ (1) Any shares purchased outside of publicly announced plans or programs represent shares surrendered in satisfaction of tax withholding obligations in connection with the vesting of restricted stock awards.
The dividend was paid on July 30, 2021 to stockholders of record as of the close of business on June 30, 2021. Since this time, our board of directors has declared and paid incrementally higher cash dividends each successive quarter.
Dividend Policy On May 6, 2021, our board of directors declared our first cash dividend on our common stock in the amount of $0.03 per share. The dividend was paid on July 30, 2021 to stockholders of record as of the close of business on June 30, 2021.
This graph tracks the performance of a $100 investment in our common stock and in each index (including reinvestment of all dividends) from December 31, 2017 to December 31, 2022. 43 Table of Contents The following table sets forth the total returns utilized to generate the foregoing graph. 12/31/2017 12/31/2018 12/31/2019 12/31/2020 12/31/2021 12/31/2022 Northern Oil & Gas, Inc. 100.00 110.24 114.15 42.73 101.14 156.18 S&P 500 100.00 95.62 125.72 148.85 191.58 156.89 NYSE Arca Oil Index 100.00 97.8 116.53 80.41 104.29 146.8 The stock price performance included in this graph is not necessarily indicative of future stock price performance.
This graph tracks the performance of a $100 investment in our common stock and in each index (including reinvestment of all dividends) from December 31, 2018 to December 31, 2023. 46 Table of Contents The following table sets forth the total returns utilized to generate the foregoing graph. 12/31/2018 12/31/2019 12/31/2020 12/31/2021 12/31/2022 12/31/2023 Northern Oil & Gas, Inc. 100.00 103.54 38.76 91.75 141.67 177.68 S&P 500 100.00 131.49 155.68 200.37 164.08 207.21 SPDR S&P Oil & Gas Exploration & Production ETF 100.00 90.56 57.59 96.03 139.60 144.57 NYSE Arca Oil Index 100.00 119.15 82.22 106.64 150.11 164.57 The stock price performance included in this graph is not necessarily indicative of future stock price performance.
Holders As of February 21, 2023, we had 85,273,377 shares of our common stock outstanding, held by approximately 191 stockholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.
Holders As of February 21, 2024, we had 100,873,127 shares of our common stock outstanding, held by approximately 183 stockholders of record.
The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors.
In connection with the announcement of the latest dividend declaration, we affirmed our intention to set our dividend policy once per year, and currently anticipate maintaining a $0.40 per share quarterly dividend throughout 2024. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors.
Added
Because we believe the new index is a more appropriate index for comparison, in 2023 we chose to compare our cumulative total stockholder return against the SPDR S&P Oil & Gas Exploration & Production ETF (the “XOP”), instead of the NYSE Arca Oil Index (the “Arca Index”).
Added
If a company selects a different index for comparison from that used in the immediately preceding fiscal year, the company’s stock performance must be compared with both the newly-selected index and the index used in the immediately preceding year.
Added
Subsequently, our board of directors declared and paid incrementally higher quarterly cash dividends through the $0.40 per share cash dividend declared on October 30, 2023 and paid on January 31, 2024 to stockholders of record as of the close of business on December 28, 2023.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

98 edited+13 added−16 removed67 unchanged
Biggest changeOur financial and operating performance for the year ended December 31, 2022 included the following: • Oil and natural gas sales of $1,985.8 million, a 104% increase compared to 2021 • Cash flows from operations of $928.4 million, a 134% increase compared to 2021 • Proved reserves of 330.8 MMBoe at year-end, a 15% increase compared to year-end 2021 • Grew and diversified the business through over $955 million in substantial bolt-on acquisitions that closed during 2022 • Grew our quarterly common stock dividend from $0.08 per share for the fourth quarter of 2021 to $0.30 per share for the fourth quarter of 2022 • Expanded our stockholder return program by repurchasing and retiring $54.5 million of common stock, $57.5 million in liquidation value of our Series A Preferred Stock (as defined below), and $25.8 million in face value of our Senior Notes • Simplified our balance sheet by exercising our right to force a mandatory conversion of all remaining shares of our Series A Preferred Stock in November 2022 • Issued $500.0 million in aggregate principal amount of Convertible Notes (as defined below), and used the net proceeds to reduce borrowings under our Revolving Credit Facility, fund acquisitions, and for other general corporate purposes Source of Our Revenues We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties.
Biggest changeOur financial and operating performance for the year ended December 31, 2023 included the following: • Total production of 98,822 Boe per day, a 31% increase compared to 2022 • Cash flows from operations of $1.2 billion, a 27% increase compared to 2022 • Proved reserves of 339.7 MMBoe at year-end, a 3% increase compared to year-end 2022 • Grew and diversified the business through over $1.0 billion in substantial bolt-on acquisitions that closed during 2023 • Grew our quarterly common stock dividend by 33%, from $0.30 per share for the fourth quarter of 2022 to $0.40 per share for the fourth quarter of 2023 Source of Our Revenues We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties.
If a low price environment reoccurs, we might be required to further write down the value of our oil and gas properties. In addition, capitalized ceiling impairment charges may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly. See “Item 2. Properties” for a discussion of our reserve estimation assumptions.
If a low price environment reoccurs, we might be required to write down the value of our oil and gas properties. In addition, capitalized ceiling impairment charges may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly. See “Item 2. Properties” for a discussion of our reserve estimation assumptions.
Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital. We may also choose to seek additional capital rather than utilize our credit facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions.
Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital. We may also choose to seek additional capital rather than utilize our Revolving Credit Facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions.
We include interest expense that is not capitalized into the full cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense. • Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter.
We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense. • Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter.
Selected Factors That Affect Our Operating Results Our revenues, cash flows from operations and future growth depend substantially upon: • the timing and success of drilling and production activities by our operating partners; • the prices and the supply and demand for oil, natural gas and NGLs; 47 Table of Contents • the quantity of oil and natural gas production from the wells in which we participate; • changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices; • our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and • the level of our operating expenses.
Selected Factors That Affect Our Operating Results Our revenues, cash flows from operations and future growth depend substantially upon: • the timing and success of drilling and production activities by our operating partners; • the prices and the supply and demand for oil, natural gas and NGLs; • the quantity of oil and natural gas production from the wells in which we participate; • changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices; • our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and • the level of our operating expenses.
Our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc., audited 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2022. Our estimates of proved reserves quantities were prepared in accordance with the rules promulgated by the SEC.
Our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc., audited 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2023. Our estimates of proved reserves quantities were prepared in accordance with the rules promulgated by the SEC.
Off-Balance Sheet Arrangements We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. 59 Table of Contents
Off-Balance Sheet Arrangements We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. 62 Table of Contents
Satisfaction of Our Cash Obligations for the Next Twelve Months With our revolving credit agreement and our cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months and, based on current expectations, for the foreseeable future.
Satisfaction of Our Cash Obligations for the Next Twelve Months With our Revolving Credit Facility and our cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months and, based on current expectations, for the foreseeable future.
As of December 31, 2022, we h ad no outsta nding shares of Series A Preferred Stock. See Note 5 to our financial statements for further details regarding the Series A Preferred Stock and the mandatory conversion. Known Contractual and Other Obligations; Planned Capital Expenditures Contractual and Other Obligations.
As of December 31, 2023, we h ad no outsta nding shares of Series A Preferred Stock. See Note 5 to our financial statements for further details regarding the Series A Preferred Stock and the mandatory conversion. Known Contractual and Other Obligations; Planned Capital Expenditures Contractual and Other Obligations.
We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, fluctuations in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.
We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, 59 Table of Contents fluctuations in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.
In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. Approximately 35% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves.
In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. Approximately 31% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves.
The decrease in the net liability at December 31, 2022 as compared to December 31, 2021 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2021. Our open commodity derivative contracts are summarized in “Item 7A.
The decrease in the net liability at December 31, 2023 as compared to December 31, 2022 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2022. Our open commodity derivative contracts are summarized in “Item 7A.
Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the 51 Table of Contents mark-to-market value of our commodity derivatives.
Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives.
In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or if estimations of our proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity.
In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or if 61 Table of Contents estimations of our proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity.
For a summary as of December 31, 2022, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.
For a summary as of December 31, 2023, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.
These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.
These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly 50 Table of Contents during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.
Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions.
Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and 60 Table of Contents engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions.
Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties and cash settlements of commodity derivative instruments. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
Our primary uses of capital have been for the acquisition, development and operation of our oil and natural gas properties, cash settlements of commodity derivative instruments and for stockholder returns. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
If internally generated cash flow and borrowing capacity is not available under our Revolving Credit Facility, we may issue additional equity or debt to fund capital expenditures, make acquisitions, extend maturities or to repay debt.
If internally generated cash flow and borrowing capacity under our Revolving Credit Facility are not available or sufficient, we may issue additional equity or debt to fund capital expenditures, make acquisitions, extend maturities or to repay debt.
See also Note 12 to our financial statements. 49 Table of Contents Results of Operations for 2022 and 2021 The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.
See also Note 12 to our financial statements. 52 Table of Contents Results of Operations for 2023 and 2022 The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.
See Note 4 to our financial statements for further details regarding the Convertible Notes. Series A Preferred Stock In November 2022, we exercised in full our mandatory conversion rights on the Series A Preferred Stock. All outstanding shares of Series A Preferred Stock automatically converted into shares of common stock on November 15, 2022.
See Note 4 to our financial statements for further details regarding the Senior Notes due 2031. Series A Preferred Stock In November 2022, we exercised in full our mandatory conversion rights on the Series A Preferred Stock. All outstanding shares of Series A Preferred Stock automatically converted into shares of common stock on November 15, 2022.
Our estimates of our proved oil and 57 Table of Contents natural gas reserves, future development costs, estimates relating to certain oil and natural gas revenues and expenses, and fair value of derivative instruments are the most critical to our financial statements.
Our estimates of our proved oil and natural gas reserves, future development costs, estimates relating to certain oil and natural gas revenues and expenses, and fair value of derivative instruments are the most critical to our financial statements.
We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties.
However, we may seek additional access to capital and liquidity. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties.
Oil accounted for 74% and 79% of our total oil and gas sales in 2022 and 2021, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices.
Oil accounted for 87% and 74% of our total oil and gas sales in 2023 and 2022, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices.
Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark and the sales prices we receive for our production. Our oil price differential to the NYMEX benchmark price during 2022 was $2.73 per barrel, as compared to $5.15 per barrel in 2021.
Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark and the sales prices we receive for our production. Our oil price differential to the NYMEX benchmark price during 2023 was $2.83 per barrel, as compared to $2.73 per barrel in 2022.
In addition, the number of net wells we added to production (excluding acquisitions) increased by 59% in 2022 as compared to 2021, due to our growing organic acreage footprint and increased development on our properties.
In addition, the number of net wells we added to production (excluding acquisitions) increased by 35% in 2023 as compared to 2022, due to our growing organic acreage footprint and increased development on our properties.
Commodity Derivative Instruments We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our gain (loss) on commodity derivatives, net was a loss of $415.3 million in 2022, compared to a loss of $478.2 million in 2021.
Commodity Derivative Instruments We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our gain (loss) on commodity derivatives, net was a gain of $259.3 million in 2023, compared to a loss of $415.3 million in 2022.
Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end. For 2022, we realized a loss on settled commodity derivatives of $455.4 million, compared to a $165.8 million loss in 2021.
Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end. For 2023, we realized a gain on settled commodity derivatives of $57.9 million, compared to a $455.4 million loss in 2022.
The cash provided by financing activities in 2022 was primarily related to $264.0 million of net advances under our Revolving Credit Facility and issuance of Convertible Notes of $483.0 million, which was partially offset by $81.2 million in repurchases of Series A Preferred Stock, $54.5 million in repurchases of common stock, $24.9 million in repurchases of our Senior Notes, and $36.1 million of capped call purchases related to the issuance of our Convertible Notes.
The cash provided by financing activities in 2022 was primarily related to $264.0 million of net advances under our Revolving Credit Facility and issuance of Convertible Notes of $483.0 million, which was partially offset by $81.2 million in repurchases of our 6.500 % Series A Perpetual Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”), $54.5 million in repurchases of common stock, $24.9 million in repurchases of our Senior Notes due 2028, and $36.1 million of capped call purchases related to the issuance of our Convertible Notes.
During the years ended December 31, 2022 and 2021, we recorded a contingent consideration gain of $1.9 million compared to a loss of $0.3 million, respectively, due to the change in the fair value of these liabilities. As of December 31, 2022, there were $10.1 million of remaining outstanding contingent consideration liabilities.
During the years ended December 31, 2023 and 2022, we recorded a contingent consideration gain of $10.1 million compared to a gain of $1.9 million, respectively, due to the change in the fair value of these liabilities. As of December 31, 2023, there were no remaining outstanding contingent consideration liabilities.
This represented significant growth from 2021, which was driven in large part by our substantial acquisition activity in 2021 and 2022, as described in Note 3 to our financial statements. During 2022, we added 56.8 new net wells to production, plus an additional 66.4 net wells added from acquisitions which were already producing when acquired.
This represented significant growth from 2022, which was driven in large part by our substantial acquisition activity in 2022 and 2023, as described in Note 3 to our financial statements. During 2023, we added 76.6 new net wells to production, plus an additional 80.4 net wells added from acquisitions which were already producing when acquired.
Our substantial acquisition activities in 2021 and 2022 (see Note 3 to our financial statements) helped drive the 40% increase in production levels in 2022 as compared to 2021.
Our substantial acquisition activities in 2022 and 2023 (see Note 3 to our financial statements) helped drive the 31% increase in production levels in 2023 as compared to 2022.
For instance, during the year ended December 31, 2022, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g. drilling and completion costs, acquisitions, and other capital expenditures) amounted to $1,474.5 million, while the actual cash spend in this regard amounted to $1,355.2 million. Development and acquisition activities are discretionary.
For instance, during the year ended December 31, 2023, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g. drilling and completion costs, acquisitions, and other capital expenditures) amounted to $1,925.9 million, while the actual cash spend in this regard amounted to $1,861.1 million. Development and acquisition activities are discretionary.
Additionally, we paid common and preferred stock dividends of $4.9 million and $29.2 million, respectively, and spent $17.6 million in fees in connection with debt financing transactions in 2021. Revolving Credit Facility We have entered into a revolving credit facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto (the “Revolving Credit Facility”).
Additionally, we paid common and preferred stock dividends of $51.6 million and $21.7 million, respectively, and spent $7.4 million in fees in connection with debt financing transactions in 2022. Revolving Credit Facility We have entered into a revolving credit facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto (the “Revolving Credit Facility”).
We seek to maintain a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the years ended 2022 and 2021, we hedged approximately 68% and 73% of our crude oil production, respectively.
We seek to maintain 56 Table of Contents a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the years ended 2023 and 2022, we hedged approximately 65% and 68% of our crude oil production, respectively.
The price differential between our well head price for oil and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries.
Principal Components of Our Cost Structure • Commodity price differentials . The price differential between our well head price for oil and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries.
Executive Overview Our primary strategy is to invest in non-operated minority working and mineral interests in oil and gas properties, with a core area of focus in the premier basins within the United States. Using this strategy, we had participated in 8,672 gross (799.3 net) producing wells as of December 31, 2022.
Executive Overview Our primary strategy is to invest in non-operated minority working and mineral interests in oil and gas properties, with a core area of focus in the premier basins within the United States. Using this strategy, we had participated in 9,765 gross (951.6 net) producing wells as of December 31, 2023.
We had total liquidity of $683.5 million as of December 31, 2022, consisting of $681.0 million of committed borrowing availability under the Revolving Credit Facility and $2.5 million of cash on hand. One of the primary sources of variability in our cash flows from operating activities is commodity price volatility.
We had total liquidity of $1,097.2 million as of December 31, 2023, consisting of $1,089.0 million of committed borrowing availability under the Revolving Credit Facility and $8.2 million of cash on hand. One of the primary sources of variability in our cash flows from operating activities is commodity price volatility.
For 2023, we are budgeting approximately $737 to $778 million in total planned capital expenditures, including development expenditures and our smaller day-to-day acquisition activity, which we refer to as our “ground game” acquisition activity.
For 2024, we are budgeting approximately $825 to $900 million in total planned capital expenditures, including development expenditures and our smaller day-to-day acquisition activity, which we refer to as our “ground game” acquisition activity.
On an absolute dollar basis, the 53% increase in our production expenses in 2022 compared to 2021 was primarily due to a 40% increase in production volumes and a 9% increase in per unit costs. Production Taxes We pay production taxes based on realized oil and natural gas sales.
On an absolute dollar basis, the 33% increase in our production expenses in 2023 compared to 2022 was primarily due to a 31% increase in production volumes and a 2% increase in per unit costs. Production Taxes We pay production taxes based on realized oil and natural gas sales.
We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditure budget.
We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditure budget. See also “Capital Requirements” below. Capital Stock and Debt Security Repurchases .
Our cash spend for development and acquisition activities for the years ended December 31, 2022 and 2021 are summarized in the following table: Year Ended December 31, (In millions) 2022 2021 Drilling and Development Capital Expenditures $ 392.5 $ 180.8 Acquisition of Oil and Natural Gas Properties $ 958.8 410.4 Other Capital Expenditures $ 4.0 2.0 Total $ 1,355.2 $ 593.2 Cash Flows from Financing Activities Net cash provided by financing activities was $467.4 million and $246.1 million for the years ended December 31, 2022 and 2021, respectively.
Our cash spend for development and acquisition activities for the years ended December 31, 2023 and 2022 are summarized in the following table: Year Ended December 31, (In millions) 2023 2022 Drilling and Development Capital Expenditures $ 809.8 $ 392.5 Acquisition of Oil and Natural Gas Properties 1,047.7 958.8 Other Capital Expenditures 3.6 4.0 Total $ 1,861.1 $ 1,355.2 Cash Flows from Financing Activities Net cash provided by financing activities was $684.7 million and $467.4 million for the years ended December 31, 2023 and 2022, respectively.
See Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2021, which is incorporated herein by reference, for discussion and analysis of results of operations for the year ended December 31, 2020.
See Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2022 for discussion and analysis of results of operations for the year ended December 31, 2021.
With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity.
With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months and, based on current expectations, for the foreseeable future.
At December 31, 2022, all of our derivative contracts are recorded at their fair value, which was a net liability of $236.5 million, a change of $41.2 million from the $277.7 million net liability recorded as of December 31, 2021.
At December 31, 2023, all of our derivative contracts are recorded at their fair value, which was a net liability of $36.2 million, a change of $200.3 million from the $236.5 million net liability recorded as of December 31, 2022.
Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.” Production Expenses Production expenses were $260.7 million in 2022 compared to $170.8 million in 2021.
Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.” Production Expenses Production expenses were $347.0 million in 2023 compared to $260.7 million in 2022.
Our net realized gas price during 2022 was $7.43 per Mcf, representing 113% realization relative to average Henry Hub pricing, compared to a net realized gas price of $4.57 per Mcf during 2021, which represented 119% realization relative to average Henry Hub pricing.
Our net realized gas price during 2023 was $2.98 per Mcf, representing 112% realization relative to average Henry Hub pricing, compared to a net realized gas price of $7.43 per Mcf during 2022, which represented 113% realization relative to average Henry Hub pricing.
As of December 31, 2022, we had incurred $163.1 million in capital expenditures that were included in accounts payable, and we estimate that we were committed to an additional approximately $468.4 million in development capital expenditures not yet incurred for wells we had elected to participate in.
As of December 31, 2023, we had incurred $236 million in capital expenditures that were included in accounts payable and accrued liabilities, and we estimate that we were committed to an additional approximately $393 million in development capital expenditures not yet incurred for wells we had elected to participate in.
Our average realized oil price after reflecting settled oil derivatives was $69.60 per barrel of oil in 2022, or 32% higher than in 2021, due to the higher average NYMEX price and a lower oil price differential, partially offset by a larger loss on settled oil derivatives in 2022 compared to 2021.
Our average realized oil price after reflecting settled oil derivatives was $73.88 per barrel of oil in 2023, or 5% higher than in 2022, due to a significantly smaller loss on settled oil derivatives in 2023 compared to 2022, partially offset by the lower average NYMEX price and a higher oil price differential.
Depletion, Depreciation, Amortization and Accretion Depletion, depreciation, amortization and accretion (“DD&A”) was $251.3 million in 2022 compared to $140.8 million in 2021. The aggregate increase in DD&A expense for 2022 compared to 2021 was driven by a 40% increase in production levels and a 27% increase in the depletion rate per Boe.
Depletion, Depreciation, Amortization and Accretion Depletion, depreciation, amortization and accretion (“DD&A”) was $486.0 million in 2023 compared to $251.3 million in 2022. The aggregate increase in DD&A expense for 2023 compared to 2022 was driven by a 31% increase in production levels and a 48% increase in the depletion rate per Boe.
General and Administrative Expenses General and administrative expenses were $47.2 million for 2022 compared to $30.3 million for 2021. The increase in 2022 compared to 2021 was primarily due to an $8.4 million increase in acquisition costs, a $5.4 million increase in compensation costs and a $1.5 million increase in professional fees.
General and Administrative Expenses General and administrative expenses were $46.8 million for 2023 compared to $47.2 million for 2022. The decrease in 2023 compared to 2022 was primarily due to a $5.3 million decrease in acquisition costs, partially offset by a $2.5 million increase in professional fees and a $1.2 million increase in compensation costs.
For the year ended December 31, 2022, our average depletion expense per unit of production w as $9.01 per Boe. 58 Table of Contents To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount rate and based on 12-month/SEC oil and natural gas prices) of the estimated future net cash flows from our proved oil and natural gas reserves and the capitalized cost associated with our unproved properties, we would have a capitalized ceiling impairment.
To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount rate and based on 12-month/SEC oil and natural gas prices) of the estimated future net cash flows from our proved oil and natural gas reserves and the capitalized cost associated with our unproved properties, we would have a capitalized ceiling impairment.
The $105.2 million increase in current assets in 2022 as compared to 2021 was driven by a $77.8 million increase in accounts receivable, primarily due to higher production levels and higher commodity prices, and a $32.8 million increase in derivative instruments due to the change in fair value as a result of commodity price changes.
The $188.9 million increase in current assets in 2023 as compared to 2022 was driven by a $99.2 million increase in accounts receivable, primarily due to higher production levels, and a $40.4 million increase in derivative instruments due to the change in fair value as a result of commodity price changes.
Our average realized price (including all commodity derivative cash settlements) in 2022 was $55.53 per Boe compared to $41.21 per Boe in 2021. The gain (loss) on settled commodity derivatives decreased our average realized price per Boe by $16.52 in 2022, and decreased our average realized price per Boe by $8.45 in 2021.
Our average realized price (including all commodity derivative cash settlements) in 2023 was $54.22 per Boe compared to $55.53 per Boe in 2022. The gain (loss) on settled commodity derivatives increased our average realized price per Boe by $1.61 in 2023 and decreased our average realized price per Boe by $16.52 in 2022.
Senior Notes As of December 31, 2022, we had outstanding $724.2 million aggregate principal amount of our 8.125% senior notes due 2028 (the “Senior Notes”). See Note 4 to our financial statements for further details regarding the Senior Notes. Convertible Notes As of December 31, 2022, we had outstanding $500.0 million aggregate principal amount of our Convertible Notes.
Convertible Notes due 2029 As of December 31, 2023, we had outstanding $500.0 million aggregate principal amount of our Convertible Notes. See Note 4 to our financial statements for further details regarding the Convertible Notes. Senior Notes due 2031 As of December 31, 2023, we had outstanding $500.0 million aggregate principal amount of our 8.750% senior notes due 2031.
The higher average realized price in 2022 as compared to 2021 was driven by higher average NYMEX oil and natural gas prices, and a lower average oil price differential, partially offset by lower average natural gas realizations in 2022 as compared to 2021. Oil price differential during 2022 averaged $2.73 per barrel, as compared to $5.15 per barrel in 2021.
The lower average realized price in 2023 as compared to 2022 was driven by lower average NYMEX oil and natural gas prices and slightly higher average oil price differential in 2023 as compared to 2022. Oil price differential during 2023 averaged $2.83 per barrel, as compared to $2.73 per barrel in 2022.
Cash Flows from Investing Activities We had cash flows used in investing activities of $1,402.8 million and $634.4 million during the years ended December 31, 2022 and 2021, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs. The year-over-year increase in cash used in investing activities in 2022 was attributable to our 2022 acquisitions.
Cash Flows from Investing Activities We had cash flows used in investing activities of $1,862.3 million and $1,402.8 million during the years ended December 31, 2023 and 2022, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs.
At December 31, 2022, we performed an impairment review using prices that reflect an average of 2022’s monthly prices as prescribed pursuant to the SEC’s guidelines. We did not record any full cost impairment expense for the years ended December 31, 2022 or 2021, respectively. For the year ended 2020, we recorded a $1,066.7 million full cost impairment expense.
At December 31, 2023, we performed an impairment review using prices that reflect an average of 2023’s monthly prices as prescribed pursuant to the SEC’s guidelines. We did not record any full cost impairment expense for the years ended December 31, 2023 or 2022.
Quantitative and Qualitative Disclosures about Market Risk.” Our cash flows for the years ended December 31, 2022 and 2021 are presented below: 54 Table of Contents Year Ended December 31, (In thousands) 2022 2021 Net Cash Provided by Operating Activities $ 928,418 $ 396,467 Net Cash Used for Investing Activities (1,402,777) (634,434) Net Cash Provided by Financing Activities 467,367 246,059 Net Change in Cash $ (6,992) $ 8,092 Cash Flows from Operating Activities Net cash provided by operating activities in 2022 was $928.4 million, compared to $396.5 million in 2021.
Quantitative and Qualitative Disclosures about Market Risk.” Our cash flows for the years ended December 31, 2023 and 2022 are presented below: Year Ended December 31, (In thousands) 2023 2022 Net Cash Provided by Operating Activities $ 1,183,321 $ 928,418 Net Cash Used for Investing Activities (1,862,346) (1,402,777) Net Cash Provided by Financing Activities 684,692 467,367 Net Change in Cash $ 5,667 $ (6,992) Cash Flows from Operating Activities Net cash provided by operating activities in 2023 was $1,183.3 million, compared to $928.4 million in 2022.
Our production for the last two years is set forth in the following table: Year Ended December 31, 2022 2021 Production: Oil (Bbl) 16,090,072 12,288,358 Natural Gas and NGL (Mcf) 68,829,142 44,073,941 Total (Boe) (1) 27,561,596 19,634,015 Average Daily Production: Oil (Bbl) 44,082 33,667 Natural Gas and NGL (Mcf) 188,573 120,751 Total (Boe) (1) 75,511 53,792 __________________________________ (1) Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
Our production for the last two years is set forth in the following table: Year Ended December 31, 2023 2022 Production: Oil (Bbl) 22,012,986 16,090,072 Natural Gas and NGL (Mcf) 84,341,858 68,829,142 Total (Boe) (1) 36,069,962 27,561,596 Average Daily Production: Oil (Bbl) 60,310 44,082 Natural Gas and NGL (Mcf) 231,074 188,573 Total (Boe) (1) 98,822 75,511 __________________________________ (1) Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2022 and 2021. 48 Table of Contents December 31, 2022 2021 Average NYMEX Prices (1) Oil (per Bbl) $ 94.38 $ 68.09 Natural Gas (per Mcf) 6.56 3.84 ________________________ (1) Based on average NYMEX closing prices.
The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2023 and 2022. December 31, 2023 2022 Average NYMEX Prices (1) Oil (per Bbl) $ 77.61 $ 94.38 Natural Gas (per Mcf) 2.66 6.56 ________________________ (1) Based on average NYMEX closing prices.
In 2022, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increased 104% from 2021, driven by a 40% increase in production volumes and a 45% increase in realized prices, excluding the effect of settled commodity derivatives.
In 2023, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, decreased 4% from 2022, driven by a 27% decrease in realized prices, excluding the effect of settled commodity derivatives, partially offset by a 31% increase in production volumes.
During the year ended December 31, 2022 the Company repurchased 1,909,097 shares of its common stock under the stock repurchase program at a total cost of $54.5 million.
During the year ended December 31, 2023 the Company repurchased 287,751 shares of its common stock under the stock repurchase program at a total cost of $8.0 million.
The Company may in the future engage in similar transactions. 56 Table of Contents The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors.
The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors.
As of December 31, 2022, we had leased approximately 258,970 net acres, of which approximately 88% were developed and all were located in the United States. Our average daily production for full year 2022 was 75,511 Boe per day, and in the fourth quarter of 2022 was 78,854 Boe per day (approximately 59% oil).
As of December 31, 2023, we had leased approximately 272,251 net acres, of which approximately 89% were developed and all were located in the United States. Our average daily production for full year 2023 was 98,822 Boe per day, and in the fourth quarter of 2023 was 114,363 Boe per day (approximately 60% oil).
Unsettled commodity derivative gains and losses was a gain of $40.2 million in 2022 compared to a loss of $312.4 million in 2021. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings.
Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized 54 Table of Contents immediately into earnings.
During the year ended December 31, 2022, the Company also repurchased and retired $25.8 million in aggregate principal amount of the Senior Notes in open market transactions for a total of $24.9 million in cash, plus accrued interest.
During the year ended December 31, 2023, the Company also repurchased and retired $19.1 million in aggregate principal amount of the Senior Notes due 2028 in open market transactions for a total of $18.4 million in cash, plus accrued interest. The Company may in the future engage in similar transactions.
Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity.
During 2023 and 2022, we added 76.6 and 56.8 net wells to production, respectively, excluding already producing wells from acquisitions. Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity.
We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production. For a summary as of December 31, 2022, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Item 7A below.
For a summary as of December 31, 2023, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Item 7A below.
Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties. • Production taxes.
Such costs also include 49 Table of Contents field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties. • Production taxes.
Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. See “Item 7A.
We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. See “Item 7A.
Years Ended December 31, 2022 2021 Net Production: Oil (Bbl) 16,090,072 12,288,358 Natural Gas and NGLs (Mcf) 68,829,142 44,073,941 Total (Boe) 27,561,596 19,634,015 Net Sales (in thousands): Oil Sales $ 1,474,610 $ 773,474 Natural Gas and NGL Sales 511,188 201,619 Gain (Loss) on Settled Commodity Derivatives (455,450) (165,823) Gain (Loss) on Unsettled Commodity Derivatives 40,187 (312,370) Total Revenues 1,570,535 496,899 Average Sales Prices: Oil (per Bbl) $ 91.65 $ 62.94 Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl) (22.05) (10.17) Oil Net of Settled Oil Derivatives (per Bbl) 69.60 52.77 Natural Gas and NGLs (per Mcf) 7.43 4.57 Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) (1.60) (0.92) Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 5.83 3.65 Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 72.05 49.66 Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) (16.52) (8.45) Realized Price on a Boe Basis Including Settled Commodity Derivatives 55.53 41.21 Operating Expenses (in thousands): Production Expenses $ 260,676 $ 170,817 Production Taxes 158,194 76,954 General and Administrative Expenses 47,200 30,341 Depletion, Depreciation, Amortization and Accretion 251,272 140,828 Costs and Expenses (per Boe): Production Expenses $ 9.46 $ 8.70 Production Taxes 5.74 3.92 General and Administrative Expenses 1.71 1.55 Depletion, Depreciation, Amortization and Accretion 9.12 7.17 Net Producing Wells at Period-End 799.3 680.8 50 Table of Contents Oil and Natural Gas Sales Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes.
Year Ended December 31, 2023 2022 Net Production: Oil (Bbl) 22,012,986 16,090,072 Natural Gas and NGLs (Mcf) 84,341,858 68,829,142 Total (Boe) 36,069,962 27,561,596 Net Sales (in thousands): Oil Sales $ 1,646,096 $ 1,474,610 Natural Gas and NGL Sales 251,683 511,188 Gain (Loss) on Settled Commodity Derivatives 57,919 (455,450) Gain on Unsettled Commodity Derivatives 201,331 40,187 Other Revenue 9,230 — Total Revenues 2,166,259 1,570,535 Average Sales Prices: Oil (per Bbl) $ 74.78 $ 91.65 Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) (0.90) (21.48) Oil Net of Settled Oil Derivatives (per Bbl) 73.88 70.17 Natural Gas and NGLs (per Mcf) 2.98 7.43 Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.92 (1.60) Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 3.90 5.83 Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 52.61 72.05 Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) 1.61 (16.52) Realized Price on a Boe Basis Including Settled Commodity Derivatives 54.22 55.53 Operating Expenses (in thousands): Production Expenses $ 347,006 $ 260,676 Production Taxes 160,118 158,194 General and Administrative Expenses 46,801 47,201 Depletion, Depreciation, Amortization and Accretion 486,024 251,272 Other Expenses 4,448 — Costs and Expenses (per Boe): Production Expenses $ 9.62 $ 9.46 Production Taxes 4.44 5.74 General and Administrative Expenses 1.30 1.71 Depletion, Depreciation, Amortization and Accretion 13.47 9.12 Net Producing Wells at Period-End 951.6 799.3 53 Table of Contents Oil and Natural Gas Sales Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes.
For 2022, the average NYMEX pricing for natural gas was $6.56 per Mcf, or 71% higher than in 2021. Our average realized natural gas price before reflecting settled natural gas derivatives was $7.43 per Mcf in 2022.
For 2023, the average NYMEX pricing for natural gas was $2.66 per Mcf, or 59% lower than in 2022. Our average realized natural gas price before reflecting settled natural gas derivatives was $2.98 per Mcf in 2023.
Changes in working capital and other items (as reflected in our statements of cash flows) in the year ended December 31, 2022 was a deficit of $62.4 million compared to a deficit of $85.8 million in 2021.
Net cash provided by operating activities is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital and other items (as reflected in our statements of cash flows) in the year ended December 31, 2023 was a deficit of $106.1 million compared to a deficit of $62.4 million in 2022.
For 2022, the average NYMEX pricing was $94.38 per barrel of oil, or 39% higher than in 2021. Our average realized oil price before reflecting settled oil derivatives was $91.65 per barrel of oil in 2022.
For 2023, the average NYMEX pricing was $77.61 per barrel of oil, or 18% lower than in 2022. Our average realized oil price before reflecting settled oil derivatives was $74.78 per barrel of oil in 2023.
As of December 31, 2022, the Revolving Credit Facility had a borrowing base of $1.6 billion and an elected commitment amount of $1.0 billion, and we had $319.0 million in borrowings outstanding under the facility, leaving $681.0 million in available committed borrowing capacity. See Note 4 to our financial statements for further details regarding the Revolving Credit Facility.
As of December 31, 2023, the Revolving Credit Facility had a borrowing base of $1.8 billion and an elected commitment amount of $1.25 billion, and we had $161.0 million in borrowings outstanding under the facility, leaving $1,089.0 million in available committed borrowing capacity.
At December 31, 2022, we had a working capital deficit of $24.5 million, compared to a deficit of $112.2 million at December 31, 2021. Current assets increased by $105.2 million and current liabilities increased by $17.4 million at December 31, 2022, compared to December 31, 2021.
At December 31, 2023, we had a working capital surplus of $123.6 million, compared to a deficit of $24.5 million at December 31, 2022. Current assets increased by $188.9 million and current liabilities increased by $40.8 million at December 31, 2023 as compared to December 31, 2022.
Additionally, we paid common and preferred stock dividends of $51.6 million and $21.7 million, respectively, and spent $7.4 million in fees in connection with debt financing transactions in 2022.
Additionally, we paid common stock dividends of $123.9 million and spent $11.9 million in fees in connection with debt financing transactions in 2023.
The $17.4 million increase in current liabilities in 2022 as compared to 2021 was driven by a $79.3 million increase in accounts payable and accrued expenses, primarily as a result of increased development activity, a $10.1 million increase in contingent consideration liabilities related to our acquisition activities (see Note 3 to our financial statements), and a $3.8 million increase in accrued interest.
The $40.8 million increase in current liabilities in 2023 as compared to 2022 was driven by a $90.3 million increase in accounts payable and accrued liabilities, primarily as a result of increased development activity, and a $1.9 million increase in accrued interest.
We ended 2022 with 55.4 net wells in process.
We ended 2023 with 66.5 net wells in process.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeNatural Gas Contracts Swaps (1) Collars Contract Period Volume (MMBTU) Weighted Average Price ($/MMBTU) Volume (MMBTU) Weighted Average Ceiling Price ($/MMBTU) Weighted Average Floor Price ($/MMBTU) 2023: Q1 7,285,000 4.11 2,065,000 6.96 4.14 Q2 4,922,000 4.59 4,777,500 6.58 4.19 Q3 4,922,000 4.63 5,060,000 6.67 4.18 Q4 4,042,000 4.66 6,285,000 6.90 4.13 2024: Q1 2,730,000 4.46 1,592,500 7.92 4.00 Q2 2,484,000 4.07 227,500 8.70 4.00 Q3 2,484,000 4.07 — — — Q4 1,342,000 4.05 — — — _____________ (1) This table does not include volumes subject to call options, which are natural gas derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties.
Biggest changeNatural Gas Contracts Swaps (1) Collars Contract Period Volume (MMBTU) Weighted Average Price ($/MMBTU) Volume Ceiling (MMBTU) Volume Floor (MMBTU) Weighted Average Ceiling Price ($/MMBTU) Weighted Average Floor Price ($/MMBTU) 2024: Q1 10,816,616 $ 3.57 4,725,000 4,725,000 $ 5.21 $ 3.29 Q2 10,870,805 3.45 5,062,500 5,062,500 4.50 3.05 Q3 10,860,457 3.49 5,520,000 5,520,000 4.74 3.06 Q4 7,722,909 3.49 6,336,586 6,336,586 5.15 3.10 2025: Q1 1,485,000 $ 3.61 7,416,417 7,416,417 $ 5.54 $ 3.16 Q2 915,000 3.60 6,931,297 6,931,297 5.22 3.16 Q3 920,000 3.60 6,567,569 6,567,569 5.28 3.16 Q4 765,000 3.52 5,778,723 5,778,723 5.44 3.15 2026: Q1 450,000 $ 3.20 4,048,249 4,048,249 $ 5.66 $ 3.13 Q2 455,000 3.20 4,184,706 4,184,706 5.66 3.13 Q3 460,000 3.20 4,184,706 4,184,706 5.66 3.13 Q4 460,000 3.20 2,774,642 2,774,642 5.66 3.13 _____________ (1) This table does not include volumes subject to swaptions and call options, which are natural gas derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties.
This table also does not include basis swaps. See Note 12 to our financial statements for further details regarding our commodity derivatives, including the call options and basis swaps that are not included in the foregoing table. Interest Rate Risk Our long-term debt as of December 31, 2022 was comprised of borrowings that contain fixed and floating interest rates.
This table also does not include basis swaps. See Note 12 to our financial statements for further details regarding our commodity derivatives, including the call options and basis swaps that are not included in the foregoing table. Interest Rate Risk Our long-term debt as of December 31, 2023 was comprised of borrowings that contain fixed and floating interest rates.
Any interim cash needs are funded by cash from operations or borrowings under our Revolving Credit Facility. The following table summarizes our open crude oil derivative contracts as of December 31, 2022, by fiscal quarter.
Any interim cash needs are funded by cash from operations or borrowings under our Revolving Credit Facility. The following table summarizes our open crude oil derivative contracts as of December 31, 2023, by fiscal quarter.
Properties - Proved Reserves Sensitivity by Price Scenario” for estimates of how a decrease in oil and gas prices from the 2022 SEC Case to the $70 Flat Case would reduce our proved reserves volumes and the PV-10 value thereof. We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to commodity price volatility.
Properties - Proved Reserves Sensitivity by Price Scenario” for estimates of how a change in oil and gas prices from the 2023 SEC Case to the $70 Flat Case would reduce our proved reserves volumes and the PV-10 value thereof. We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to commodity price volatility.
A 1% increase in short-term interest rates on our floating-rate debt outstanding at December 31, 2022 would cost us approximately $2.2 million in additional annual interest expense.
A 1% increase in short-term interest rates on our floating-rate debt outstanding at December 31, 2023 would cost us approximately $1.6 million in additional annual interest expense.
See Note 12 to our financial 60 Table of Contents statements for further details regarding our commodity derivatives, including the swaptions and call options that are not included in the foregoing table. The following table summarizes our open natural gas derivative contracts as of December 31, 2022, by fiscal quarter.
This table also does not include 63 Table of Contents basis swaps. See Note 12 to our financial statements for further details regarding our commodity derivatives, including the swaptions and call options that are not included in the foregoing table. The following table summarizes our open natural gas derivative contracts as of December 31, 2023, by fiscal quarter.
The Company uses interest rate swaps to effectively convert a portion of its variable rate indebtedness to fixed rate indebtedness. As of December 31, 2022, we had interest rate swaps with a total notional amount of $100.0 million. Changes in interest rates can impact results of operations and cash flows.
From time to time, the Company may use interest rate swaps to effectively convert a portion of its variable rate indebtedness to fixed rate indebtedness. As of December 31, 2023, we had no interest rate swaps. Changes in interest rates can impact results of operations and cash flows.
Crude Oil Contracts Swaps (1) Collars Settlement Period Volume (Bbls) Weighted Average Price ($/Bbl) Volume (Bbls) Weighted Average Ceiling Price ($/Bbl) Weighted Average Floor Price ($/Bbl) 2023: Q1 2,020,500 72.39 996,750 92.00 76.68 Q2 2,161,250 75.85 887,250 89.76 73.85 Q3 1,782,500 77.17 943,000 88.66 73.66 Q4 1,725,000 76.10 989,000 87.37 73.49 2024: Q1 643,825 78.10 534,625 89.21 70.85 Q2 641,550 77.04 534,625 85.62 69.36 Q3 632,500 75.34 494,500 84.87 69.53 Q4 259,900 69.63 425,500 85.99 69.86 2025: Q1 — — 135,000 80.77 70.00 Q2 — — 136,500 77.94 70.00 Q3 — — 115,000 76.01 70.00 Q4 — — 92,000 78.02 70.00 _____________ (1) This table does not include volumes subject to swaptions and call options, which are crude oil derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties.
Crude Oil Contracts Swaps (1) Collars Settlement Period Volume (Bbls) Weighted Average Price ($/Bbl) Volume Ceiling (Bbls) Volume Floor (Bbls) Weighted Average Ceiling Price ($/Bbl) Weighted Average Floor Price ($/Bbl) 2024: Q1 2,130,923 $ 75.30 2,423,147 1,771,928 $ 84.43 $ 70.32 Q2 2,047,737 74.55 2,424,137 1,782,017 84.06 69.90 Q3 2,081,096 73.88 1,196,056 1,044,256 80.90 69.49 Q4 1,699,109 72.46 1,045,749 871,800 81.73 69.10 2025: Q1 567,749 $ 71.99 413,286 314,849 $ 79.20 $ 67.84 Q2 554,133 72.15 273,171 199,233 75.49 67.63 Q3 552,394 71.75 234,994 161,970 75.76 67.88 Q4 548,911 71.75 208,511 135,487 76.87 67.63 2026: Q1 263,726 $ 69.05 43,226 39,289 $ 70.25 $ 62.50 Q2 266,657 68.98 43,707 39,727 70.25 62.50 Q3 269,587 68.91 44,187 40,163 70.25 62.50 Q4 269,587 68.83 44,187 40,163 70.25 62.50 _____________ (1) This table does not include volumes subject to swaptions and call options, which are crude oil derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties.

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