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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020

or

☐        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________ to _______________

Commission file number: 001-31899

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Securities registered pursuant to Section 12(b) of the Act:

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Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ☒    No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes  ☐    No  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes  ☐    No  ☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.   Yes  ☒    No  ☐

Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2020:  $102,673,000.

Number of shares of the registrant’s common stock outstanding at February 17, 2021: 39,000,022 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2021 Annual Meeting of Stockholders are incorporated by reference into Part III.

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TABLE OF CONTENTS

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GLOSSARY OF CERTAIN DEFINITIONS

Unless the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used in this Annual Report on Form 10-K refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries.  When the context requires, we refer to these entities separately.

We have included below the definitions for certain terms used in this Annual Report on Form 10-K:

“ASC” Accounting Standards Codification.

“Bankruptcy Code” Title 11 of the United States Code.

“Bankruptcy Court” United States Bankruptcy Court for the Southern District of Texas.

“Basis Swap” A derivative instrument that guarantees a fixed price differential to NYMEX at a specified delivery point.  We receive the difference between the floating market price differential and the fixed price differential from the counterparty if the floating market differential is greater than the fixed price differential for the hedged commodity.  We pay the difference between the floating market price differential and the fixed price differential to the counterparty if the fixed price differential is greater than the floating market differential for the hedged commodity.

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil, NGLs and other liquid hydrocarbons.

“Bcf” One billion cubic feet, used in reference to natural gas.

“BOE” One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.

“Btu” or “British thermal unit” The quantity of heat required to raise the temperature of one pound of water one degree Fahrenheit.

“completion” The process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production.

“costless collar” An option position where the proceeds from the sale of a call option at its inception fund the purchase of a put option at its inception.  

“deterministic method” The method of estimating reserves or resources using a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation.

“development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“differential” The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.

“dry hole” or “dry well” A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

“EOR” Enhanced oil recovery.

“exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

“extension well” A well drilled to extend the limits of a known reservoir.

“FASB” Financial Accounting Standards Board.

“field” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.  There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both.  Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field.  The geological terms “structural feature” and “stratigraphic condition”

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are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

“GAAP” Generally accepted accounting principles in the United States of America.

“gross acres” or “gross wells” The total acres or wells, as the case may be, in which a working interest is owned.

“ISDA” International Swaps and Derivatives Association, Inc.

“lease operating expense” or “LOE” The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

“LIBOR” London interbank offered rate.

“MBbl” One thousand barrels of oil, NGLs or other liquid hydrocarbons.

“MBbl/d” One MBbl per day.

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

“Mcf” One thousand cubic feet, used in reference to natural gas.

“MMBbl” One million barrels of oil, NGLs or other liquid hydrocarbons.

“MMBOE” One million BOE.

“MMBtu” One million British Thermal Units, used in reference to natural gas.

“MMcf” One million cubic feet, used in reference to natural gas.

“MMcf/d” One MMcf per day.

“net acres” or “net wells” The sum of the fractional working interests owned in gross acres or wells, as the case may be.

“net production” The total production attributable to our fractional working interest owned.

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

“PDNP” Proved developed nonproducing reserves.

“PDP” Proved developed producing reserves.

“plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.  Regulations of most states legally require plugging of abandoned wells.

“pre-tax PV10%” The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the guidelines of the SEC, net of estimated lease operating expense, transportation, gathering, compression and other expense, production taxes and future development costs, using costs as of the date of estimation without future escalation and using an average of the first-day-of-the-month price for each of the 12 months within the fiscal year, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or federal income taxes and discounted using an annual discount rate of 10%.  Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC.  Refer to the footnote to the Proved Reserves table in Item 1. “Business” of this Annual Report on Form 10-K for more information.

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“probabilistic method” The method of estimating reserves using the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) to generate a full range of possible outcomes and their associated probabilities of occurrence.

“prospect” A property on which indications of oil or gas have been identified based on available seismic and geological information.

“proved developed reserves” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

“proved reserves” Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir considered as proved includes all of the following:

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.  The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“proved undeveloped reserves” or “PUDs” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.  Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.  Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

“recompletion” An operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within the existing wellbore.

“reserves” Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable

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expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“resource play” An expansive contiguous geographical area with known accumulations of crude oil or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.

“royalty” The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil or natural gas produced and sold, unencumbered by expenses relating to the drilling, completing or operating of the affected well.

“royalty interest” An interest in an oil or natural gas property entitling the owner to shares of the crude oil or natural gas production free of costs of exploration, development and production operations.

“SEC” The United States Securities and Exchange Commission.

“standardized measure of discounted future net cash flows” or “Standardized Measure” The discounted future net cash flows relating to proved reserves based on the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period (unless prices are defined by contractual arrangements, excluding escalations based upon future conditions); current costs and statutory tax rates (to the extent applicable); and a 10% annual discount rate.

“turn-in-line” or “TIL” To turn a drilled and completed well online to begin sales.

“working interest” The interest in a crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all associated risks.

“workover” Operations on a producing well to restore or increase production.

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PART I

Item 1.       Business

Overview

We are an independent oil and gas company engaged in development, production and acquisition activities primarily in the Rocky Mountains region of the United States where we are focused on developing our large resource play in the Williston Basin of North Dakota and Montana.  

On April 1, 2020, we and certain of our subsidiaries (collectively, the “Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of the Bankruptcy Code.  On June 30, 2020, the Debtors filed the Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation and its Debtor affiliates (as amended, modified, and supplemented, the “Plan”).  On August 14, 2020, the Bankruptcy Court confirmed the Plan and on September 1, 2020 (the “Emergence Date”), the Debtors satisfied all conditions required for Plan effectiveness and emerged from the Chapter 11 Cases.  Upon emergence, we adopted fresh start accounting in accordance with FASB ASC Topic 852 – Reorganizations, which specifies the accounting and financial reporting requirements for entities reorganizing through chapter 11 bankruptcy proceedings.  The application of fresh start accounting resulted in a new basis of accounting and us becoming a new entity for financial reporting purposes.  As a result of the implementation of the Plan and the application of fresh start accounting, the consolidated financial statements after the Emergence Date are not comparable to the consolidated financial statements before that date and the historical financial statements on or before the Emergence Date are not a reliable indicator of our financial condition and results of operations for any period after our adoption of fresh start accounting.  Refer to the “Fresh Start Accounting” footnote in the consolidated financial statements in Item 8 of this Annual Report on Form 10-K for more information.  References to “Successor” refer to the Whiting entity and its financial position and results of operations after the Emergence Date.  References to “Predecessor” refer to the Whiting entity and its financial position and results of operations on or before the Emergence Date.  

Since our inception, we have built a strong asset base through a combination of property acquisitions, development of proved reserves and exploration activities.  Our current operations and capital programs are focused on drilling opportunities and on the development of previously acquired properties, specifically on projects that we believe provide the greatest potential for repeatable success, while selectively pursuing acquisitions that complement our existing core properties.  As a result of the sharp decline in commodity prices during 2020 as well as our chapter 11 reorganization, we significantly reduced our level of capital spending during 2020 to more closely align with our reduced cash flows from operating activities.  We concentrated our capital program on projects that we expect to generate acceptable rates of return in the current price environment.  We continually evaluate our property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own, such as the activity discussed below under “Acquisitions and Divestitures.”

As of December 31, 2020, our estimated proved reserves totaled 260.2 MMBOE and our 2020 average daily production was 98.6 MBOE/d.

The following table summarizes by core area, our estimated proved reserves as of December 31, 2020 with the corresponding pre-tax PV10% values, our fourth quarter 2020 average daily production rates, and our total standardized measure of discounted future net cash flows as of December 31, 2020:

During 2020, we incurred $209 million in exploration and development (“E&D”) expenditures, which consisted of $185 million incurred by the Predecessor and $24 million incurred by the Successor, and includes $208 million for the drilling and completion of 54 gross (30.4 net) wells.  

Our current 2021 E&D budget is a range of $228 million to $252 million, which we expect to fund with net cash provided by operating activities and cash on hand.  Our level of E&D expenditures is largely discretionary, although a portion of our E&D expenditures are for non-operated properties where we have limited control over the timing and amount of such expenditures, and the amount of funds we devote to any particular activity may increase or decrease significantly depending on commodity prices, cash flows, available opportunities and development results, among other factors.  To the extent net cash provided by operating activities is higher or lower than currently anticipated, we would generate more or less free cash flow than we currently anticipate, adjust our E&D budget accordingly or adjust borrowings outstanding under our credit facility.

Acquisitions and Divestitures

2020 Acquisitions and Divestitures.  In January 2020, we completed the divestiture of our interests in 30 non-operated, producing oil and gas wells and related undeveloped acreage located in McKenzie County, North Dakota for aggregate sales proceeds of $25 million (before closing adjustments).  The divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2019 and 1% of our average daily production for the year ended December 31, 2019.

There were no significant acquisitions during the year ended December 31, 2020.

2019 Acquisitions and Divestitures.  In July 2019, we completed the divestiture of our interests in 137 non-operated, producing oil and gas wells located in McKenzie, Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $27 million (before closing adjustments).  

In August 2019, we completed the divestiture of our interests in 58 non-operated, producing oil and gas wells located in Richland County, Montana and Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $26 million (before closing adjustments).

On a combined basis, the divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2018 and our April 2019 average daily production.

There were no significant acquisitions during the year ended December 31, 2019.

2018 Acquisitions and Divestitures.  In July 2018, we completed the acquisition of approximately 54,800 net acres in the Williston Basin, including interests in 117 producing oil and gas wells and undeveloped acreage located in Richland County, Montana and McKenzie County, North Dakota for an aggregate purchase price of $130 million (before closing adjustments).  The producing properties had estimated proved reserves of 25.7 MMBOE as of the acquisition date, 84% of which were crude oil and NGLs.

There were no significant divestitures during the year ended December 31, 2018.

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Business Strategy

Our goal is to generate meaningful growth in shareholder value through the development, production and acquisition of oil and gas projects with attractive rates of return on invested capital.  Specifically, we have focused, and plan to continue to focus, on the following:

Efficiently Developing and Producing our Existing Properties.  The development of our large resource play at our Williston Basin project in North Dakota and Montana continues to be our central objective.  We have assembled approximately 729,700 gross (478,400 net) developed and undeveloped acres in this area.  During 2020, we completed and brought online 46 gross (27.6 net) operated Bakken and Three Forks wells in the Williston Basin.  As a result of the significant decline in crude oil prices in 2020, we suspended all drilling and completion activity and terminated our drilling rig contracts in April 2020.  During the fourth quarter of 2020, we resumed completion activity, and in February 2021, we brought on a drilling rig.  Under our current 2021 capital program, we expect to TIL approximately 56 gross (36.8 net) wells in this area during the year.

At our Redtail field in the Denver-Julesburg Basin in Weld County, Colorado, we have assembled approximately 82,700 gross (71,600 net) developed and undeveloped acres.  We completed and TIL 2 gross (1.9 net) wells in our Redtail field during 2020.  

Disciplined Financial Approach.  Our goal is to remain financially strong, yet flexible, through the prudent management of our balance sheet and active management of our exposure to commodity price volatility.  We have historically funded our acquisition and development activity through a combination of internally generated cash flows, equity and debt issuances, bank borrowings and certain oil and gas property divestitures, as appropriate, to maintain our financial position.  As a result of the sharp decline in commodity prices during 2020 as well as our chapter 11 reorganization, we significantly reduced our level of capital spending and implemented various cost reduction measures during 2020 to more closely align our expenditures with our reduced cash flows from operating activities.  We have concentrated our capital program on projects that we expect to generate acceptable rates of return in the current price environment.  From time to time, we monetize non-core properties and use the net proceeds from these asset sales to repay debt under our credit agreement or fund our E&D expenditures.  For example, during 2020 and 2019 we sold certain oil and gas properties operated by third parties that no longer matched the profile of properties we desire to own.  In addition, to support cash flow generation on our existing properties and help ensure expected cash flows from newly acquired properties, we periodically enter into derivative contracts.  Typically, we use costless collars and swaps to provide an attractive base commodity price level.  

Commitment to Safety and Social Responsibility.  We are committed to developing the resources the world needs in a safe and responsible way.  We seek ways to better protect habitats and communities, find alternatives to freshwater use, reduce the lifecycle methane emissions of our operations and encourage waste reduction programs.  Additionally, we are committed to transparency in reporting our environmental, social and governance performance.  See our Sustainability Report published on our website for sustainability performance highlights and additional information.  Information contained in our Sustainability Report is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

Growing Through Accretive Acquisitions.  Since 2010, we have completed 7 separate significant acquisitions of producing properties for total estimated proved reserves of 240.2 MMBOE, as of the effective dates of the acquisitions.  Our experienced team of management, land, engineering and geoscience professionals has executed an acquisition program designed to increase reserves and complement our existing properties, including closing purchases and effectively managing the properties we acquire.  We intend to selectively pursue the acquisition of properties that are complementary to our core operating areas, as well as explore opportunities in other basins where we can apply our existing knowledge and expertise to build production and add proved reserves.

Competitive Strengths

We believe that our key competitive strengths lie in our focused asset portfolio, our experienced management and technical teams, our commitment to the effective application of new technologies and our commitment to cost management.

Focused, Long-Lived Asset Base.  As of December 31, 2020, we had interests in 5,011 gross (2,175 net) productive wells on approximately 856,900 gross (567,000 net) developed acres across our geographical areas.  We believe the concentration of our operated assets presents us with multiple opportunities to successfully execute our business strategy by enabling us to leverage our technical expertise and take advantage of operational efficiencies.

Experienced Management and Technical Teams.  Our management team averages 24 years of experience in the oil and gas industry.  Our personnel have extensive experience in our core geographical areas, all of our operational disciplines and the evaluation, acquisition and operational assimilation of oil and gas properties.

Commitment to Technology.  In each of our core operating areas, we have accumulated extensive engineering, operational, geologic and geophysical technical knowledge.  Our technical team has access to an abundance of digital well log, seismic, completion, production and other subsurface information, which is analyzed in order to accurately and efficiently characterize the anticipated performance of

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our oil and gas reservoirs.  In addition, our information systems enable us to monitor and update our production databases through field automation.  This commitment to technology has increased the productivity and efficiency of our field operations and development activities.  Administratively, we have leveraged information systems to reduce duplications of data which has increased information reliability and minimized redundant processes.

We continue to advance our completion techniques by utilizing custom, right-sized completion designs based on calibrated models for each of our prospect areas, incorporating multivariate analysis and piloting and adopting the latest completion technologies available.  Our multivariate analysis workflow leverages public and proprietary data to solve for production and cost, using those results to optimize well design details for maximum asset value.  We plan to continue to use right-sized completion designs on wells we drill in 2021 and to expand our application of data analytics and multivariate analysis to unlock value across the business.  Additionally, we plan to continue to reduce time-on-location and total well cost while maximizing our lateral footage through drilling best practices including utilizing top tier drilling rigs, advanced downhole motor and drill bit technology and our custom drilling fluid system.

Commitment to Cost Management.  We are committed to cost reduction strategies to become a lower-cost basin operator.  As a result of the sharp decline in commodity prices during 2020 as well as our chapter 11 reorganization, we significantly reduced our operating and overhead costs during 2020.  In September 2020 and August 2019, we executed workforce reductions as part of our organizational redesign and cost reduction strategies to better align our business with the current operating environment.  During 2020, we reduced lease operating expenses across all of our properties and maintained base production with improved artificial lift techniques and targeted workovers.  These cost reduction and production maintenance efforts resulted in reducing saltwater disposal costs by 40%, extending well runtimes by 7.5% and reducing down oil volume by 35% from year-end 2019 to year-end 2020.  

We expect that our ongoing cost management efforts will result in sustainable operations and long-term value to our shareholders.

Proved Reserves

Our estimated proved reserves as of December 31, 2020 are summarized by core area in the table below.  Refer to “Reserves” in Item 2 of this Annual Report on Form 10-K for information relating to the uncertainties surrounding these reserve categories.

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Marketing

We principally sell our oil and gas production to end users, marketers and other purchasers that have access to nearby pipeline or rail takeaway.  In areas where there is no practical access to gathering pipelines, oil is trucked or transported to terminals, market hubs, refineries or storage facilities.  We believe that the loss of any individual purchaser would not have a long-term material adverse impact on our financial position or results of operations, as alternative customers and markets for the sale of our products are readily available in the areas in which we operate.

Title to Properties

Our properties are subject to customary royalty interests, liens securing indebtedness, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions.  Our credit agreement is also collateralized by a first lien 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 rights or title to all of our producing properties.  As is customary in the oil and gas industry, limited investigation of title is made at the time of acquisition of undeveloped properties.  In most cases, we investigate title and obtain title opinions from counsel only when we acquire producing properties or before commencement of drilling operations.

Competition

The oil and gas industry is a highly competitive environment for acquiring properties, obtaining investment capital, securing oil field goods and services, marketing oil and natural gas products and attracting and retaining qualified personnel.  Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate.  Those companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our resources permit.  In addition, the unavailability or high cost of drilling rigs, completion crews or other equipment and services could delay or adversely affect our development and exploration operations.  Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to obtain necessary capital as well as evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.  The price and availability of alternative energy sources, such as wind, solar, nuclear and electric power, as well as the emerging impact of climate change activism, fuel conservation measures and governmental requirements for renewable energy sources, could adversely affect our revenue.

Human Capital

We believe that in order to execute our strategy in the highly competitive oil and gas industry we need to attract, develop and retain a highly effective and diverse employee workforce.  Our ability to do so ties to a number of factors, including compensation plans, benefits programs, talent development efforts, career opportunity generation and our work environment.  As of January 31, 2021, we had approximately 405 full-time employees, 245 of which were field employees and none of which were represented by any labor unions.

Competitive Compensation and Benefits.  The objective of our compensation program is to maintain a strong pay-for-performance culture in order to attract, retain and motivate employees.  Our program includes competitive market-based salaries, short-term incentives that tie to corporate and individual performance, long-term incentives and market-competitive health and other benefits.

Training, Development and Career Opportunities. We are committed to the personal and professional development of our employees, with the belief that a greater level of knowledge, skill and ability is of personal benefit to the employee and fosters a more creative, innovative, efficient and therefore competitive company.  We strive to empower our employees to develop the skills they need to perform their current jobs while developing acumen for future opportunities.  We want our talent pool to identify a successful and fulfilling career progression within our company.

Diversity, Equity and Inclusion.  We recognize the advantages of a company culture that embraces diversity, constructive debate and differing viewpoints.  We believe that a workforce diverse in background and experience will create such a culture.  We recruit, hire, promote and perform personnel actions without regard to race, color, religion, sex, national origin, age, disability, genetic information or any other applicable status by federal, state or local law.

Safety.  “Safety Always” is one of our core, foundational values.  We strive to create a culture of safety that promotes transparency and accountability by providing the tools and resources that empower our people to identify and report potential hazards and stop work when

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necessary.  During 2020, we improved both our Total Recordable Incident Rate and our Days Away, Restricted and/or Transferred Rate from 2019.  Our goal is zero safety incidents and we continuously work toward that goal.

Government Regulation

Regulation of Production

The production of oil and gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.  Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and periodic report submittals during operations.  All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum allowable rates of production from oil and gas wells, the regulation of well spacing and the plugging and abandonment of wells.  The effect of these regulations is to limit the amount of oil and gas that we can produce from our wells and to limit the number of wells or the locations that we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing.  Moreover, each state generally imposes a production or severance tax with respect to the production or sale of oil, NGLs and natural gas within its jurisdiction.

Currently, none of our production volumes are produced from offshore leases, however, some of our prior offshore operations were conducted on federal leases that are administered by the Bureau of Ocean Energy Management (the “BOEM”).  Among other things, BOEM regulations, along with regulations of the Bureau of Safety and Environmental Enforcement (“BSEE”), govern the plugging and abandonment of wells and the removal of production facilities from these leases.  We are therefore required to comply with the regulations and orders issued by the BOEM and BSEE under the Outer Continental Shelf Lands Act. 

The Bureau of Land Management (the “BLM”) establishes the basis for onshore royalty payments due under federal oil and gas leases through regulations issued under applicable statutory authority.  State regulatory authorities establish similar standards for royalty payments due under state oil and gas leases.  The basis for royalty payments established by the BLM and the state regulatory authorities is generally applicable to all federal and state oil and gas lessees.  Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.

Regulation of Sale and Transportation of Oil

Our crude oil sales are affected by the availability, terms and cost of transportation.  The transportation of oil in common carrier pipelines is also subject to rate regulation.  The Federal Energy Regulatory Commission (the “FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act.  In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.  Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for crude oil transportation rates that allowed for an increase or decrease in the cost of transporting oil to the purchaser.  The FERC’s regulations include a methodology for oil pipelines to change their rates through the use of an index system that establishes ceiling levels for such rates.  The most recent mandatory five-year review period resulted in a 2020 order from the FERC for the index to be based on Producer Price Index for Finished Goods (the “PPI-FG”) plus 0.78 percent (PPI-FG+0.78%) for the five-year period from July 1, 2021 to June 30, 2026.  This represents a decrease from the PPI-FG plus 1.23% adjustment from the prior five-year period.  The FERC uses a calculation based on a data source that reflects actual cost-of-service data.  The regulations provide that each year the Commission will publish the oil pipeline index after the PPI-FG becomes available.  Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions.  The basis for intrastate oil pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state.  Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis.  Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates.  When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs.  In addition, the FERC has emergency authority under the Interstate Commerce Act to intervene and direct priority use of oil pipeline transportation capacity.  Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Transportation and safety of oil and hazardous liquid is subject to regulation by the Department of Transportation (the “DOT”) under the Pipeline Integrity, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2012.  The Pipeline and Hazardous Material Safety Administration (“PHMSA”), an agency within the DOT, enforces regulations on all interstate liquids transportation and some intrastate liquids transportation.  The effect of regulatory changes under the DOT and their effect on interstate and intrastate oil and hazardous liquid transportation will not affect our operations in any way that is of material difference from those of our competitors.

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A portion of our crude oil production may be shipped to market centers using rail transportation facilities owned and operated by third parties.  The DOT, generally, and PHMSA, more specifically, establish safety regulations relating to crude-by-rail transportation.  In addition, third-party rail operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the DOT, the Federal Railroad Administration (the “FRA”) of the DOT, the Occupational Safety and Health Administration and other federal regulatory agencies.  

In response to rail accidents occurring between 2002 and 2008, the U.S. Congress passed the Rail Safety and Improvement Act of 2008, which implemented regulations governing different areas related to railroad safety.  In response to train derailments occurring in the United States and Canada in 2013 and 2014, U.S. regulators have taken a number of additional actions to address the safety risks of transporting crude oil by rail.

In February 2014, the DOT issued an emergency order requiring all persons to ensure crude oil is properly tested and classed prior to offering such product into transportation, and to assure all shipments by rail of crude oil be handled as a Packing Group I or II hazardous material.  Also in February 2014, the Association of American Railroads entered into a voluntary agreement with the DOT to implement certain restrictions around the movement of crude oil by rail.  In May 2014 (and extended indefinitely in May 2015), the DOT issued an Emergency Restriction/Prohibition Order requiring each railroad carrier operating trains transporting 1,000,000 gallons or more of Bakken crude oil to provide notice to state officials regarding the expected movement of the trains through the counties in each state.  The PHMSA and FRA have also issued safety advisories and alerts regarding oil transportation and have issued a report focused on the increased volatility and flammability of Bakken crude oil as compared with other crudes in the U.S.  In May 2015, PHMSA issued new rules applicable to “high-hazard flammable trains,” defined as a continuous block of 20 or more tank cars loaded with a flammable liquid or 35 or more tank cars loaded with a flammable liquid dispersed throughout a train.  Among other requirements, the new rules require enhanced standards for newly constructed tank cars and retrofitting of existing tank cars, restricted operating speeds, a documented testing and sampling program, and routine assessments that evaluate certain safety and security factors.  In December 2015, the Fixing America’s Surface Transportation (“FAST”) Act became law, further extending PHMSA’s authority to improve the safety of transporting flammable liquids by rail and pursuant to which new regulations phasing out the use of certain older rail cars were finalized in August 2016.  In June 2016, the Protecting our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act became law.  The PIPES Act strengthens PHMSA’s safety authority, including an expansion of its ability to issue emergency orders, which was adopted by rule in October 2016 and further enhanced by rule in October 2019.  PHMSA continues to review further potential new safety regulations under the PIPES Act and the FAST Act.

We do not currently own or operate rail transportation facilities or rail cars.  However, the adoption of any regulations that impact the testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the U.S., the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.  The effect of any such regulatory changes will not affect our operations in any way that is of material difference from those of our competitors.

Regulation of Transportation, Storage, Sale and Gathering of Natural Gas

The FERC regulates the transportation and, to a lesser extent, the sale of natural gas for resale in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 and regulations issued under those Acts.  In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas, effective January 1, 1993.  While sales by producers of natural gas can currently be made at unregulated market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business.

Our natural gas sales are affected by the availability, terms and cost of transportation.  The price and terms of access to pipeline transportation and underground storage are subject to extensive federal and state regulation.  From 1985 to the present, several major regulatory changes have been implemented by Congress and the FERC that affect the economics of natural gas production, transportation and sales.  In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry that remain subject to the FERC’s jurisdiction, most notably interstate natural gas transmission companies and certain underground storage facilities.  These initiatives may also affect the intrastate transportation of natural gas under certain circumstances.  The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis.  Owners of natural gas pipelines are responsible for administering FERC-approved tariffs which govern the availability, terms and costs of transportation on specific pipelines.  Owners of natural gas pipelines may propose changes to these tariffs.  Such proposals are subject to comment by interested parties and must be approved by FERC before taking effect.  For example, in May 2020 Northern Border Pipeline Company proposed changes to the gas quality standards in its tariff which would have negatively impacted our interests and those of many other pipeline customers.  FERC ultimately rejected that proposal in November 2020, but similar proposals could be presented to FERC in the future.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in the markets in which our natural gas is sold.  Regulations implemented by the FERC could result in an increase in the cost of transportation service on certain

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petroleum product pipelines.  In addition, the natural gas industry has historically been heavily regulated.  Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC will continue.  However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Transportation and safety of natural gas is subject to regulation by the DOT under the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2012.  In addition, intrastate natural gas transportation is subject to enforcement by state regulatory agencies and PHMSA enforces regulations on interstate natural gas transportation.  State regulatory agencies can also create their own transportation and safety regulations as long as they meet PHMSA’s minimum requirements.  The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state.  Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any of the 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.  Likewise, the effect of regulatory changes by the DOT and their effect on interstate natural gas transportation will not affect our operations in any way that is of material difference from those of our competitors.

The failure to comply with these rules and regulations can result in substantial penalties.  We use the latest tools and technologies to remain compliant with current pipeline safety regulations.

In October 2015, a failure at an underground natural gas storage facility in Southern California prompted PHMSA to issue an advisory bulletin reminding owners and operators of underground storage facilities to review operations, identify the potential for facility leaks and failures and to review and update emergency plans.  The State of California proclaimed the underground natural gas storage facility an emergency situation in January 2016.  A federal task force was also convened to make recommendations to help avoid such failures.  An interim final rule of PHMSA became effective in January 2017 which adopted certain specific industry recommended practices into Part 192 of the Federal Pipeline Safety Regulations.  PHMSA later reopened the post-promulgation comment period through November 2017 in response to petitions for reconsideration and has stated it would consider such comments further when it adopts a final rule.  Under the interim final rule, if an operator fails to take any measures recommended it would need to justify in its written procedures why the measure is impracticable and unnecessary.  PHMSA regulations had previously covered much of the surface piping up to the wellhead at underground natural gas storage facilities served by pipelines and did not extend in part to the “downhole” portion of these facilities.  The adopted requirements cover design, construction, material, testing, commissioning, reservoir monitoring and recordkeeping for existing and newly constructed underground natural gas storage facilities as well as procedures and practices for newly constructed and existing underground natural gas storage facilities, such as operations, maintenance, threat identification, monitoring, assessment, site security, emergency response and preparedness, training, recordkeeping and reporting.  These regulations and any further increased attention to and requirements for underground storage safety and infrastructure by state and federal regulators that may result from this incident will not affect us in a way that materially differs from the way it affects other natural gas producers.

Environmental Regulations

General.  Our oil and gas development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge or release of materials into the environment or otherwise relating to environmental protection.  Numerous governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations to implement and enforce such laws, which often require costly compliance measures that carry substantial penalties for noncompliance.  These laws and regulations may require the acquisition of a permit before drilling or facility construction commences; restrict the types, quantities and concentrations of various materials that can be released into the environment; limit or prohibit project siting, construction or drilling activities on certain lands; require remedial and closure activities to prevent pollution from former operations; and impose substantial liabilities for unauthorized pollution.  The EPA and analogous state agencies may delay or refuse the issuance of required permits or otherwise include onerous or limiting permit conditions that may have a significant adverse impact on our ability to conduct operations.  

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly material handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our operations and financial position, as well as those of the oil and gas industry in general.  While we believe that we are in compliance, in all material respects, with current applicable environmental laws and regulations, future environmental enforcement remains a material risk due to the potential magnitude of exposure in the event of a noncompliance.  We have incurred in the past, and expect to incur in the future, capital costs related to environmental compliance.  Such expenditures are included within our overall capital and operating budgets and are not separately itemized.

The environmental laws and regulations which have the most significant impact on the oil and gas exploration and production industry are as follows:

Superfund.  The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA” or “Superfund”), and comparable state laws impose strict joint and several liability for sites contaminated by certain hazardous substances

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on classes of potentially responsible persons.  These persons include the owner or operator of the site where a release occurred and anyone who disposed of or arranged for the disposal of the hazardous substance released at the site.  Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.  In the course of our ordinary operations, we may use, generate or handle material that may be regulated as “hazardous substances.”  Consequently, we may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites where these materials have been disposed or released.

We currently own or lease, and in the past have owned or leased, properties that for many years have been used for the exploration and production of oil and gas.  Although we have used operating and disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on, under or from the properties owned or leased by us or on, under or from other locations where such substances have been taken for recycling or disposal.  In addition, many of these owned and leased properties have been previously owned or operated by third parties whose treatment and disposal of hazardous substances, wastes or hydrocarbons were not under our control and not known to us.  Similarly, the disposal facilities where discarded materials are sent are also often operated by third parties whose waste treatment and disposal practices are similarly not under our control.  While we only use what we consider to be reputable disposal facilities, we might not know of a potential problem if the problem itself is not discovered until years later.  Current and formerly owned or operated properties, adjacent affected properties, offsite disposal facilities and substances disposed or released on them may be subject to CERCLA and analogous state laws.  Under these laws, we could be required:

At this time, we do not believe that we are a potentially responsible party with respect to any Superfund site and we have not been notified of any claim, liability or damages under CERCLA or any state analog.

Oil Pollution Act.  The Oil Pollution Act of 1990 (“OPA”) and regulations issued under OPA impose strict, joint and several liability on “responsible parties” for removal costs and damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States.  A “responsible party” includes the owner or operator of an onshore facility and the lessee, permittee or holder of a right of use and easement of the area in which an offshore facility is located.  OPA establishes a liability limit for onshore facilities of $350 million per spill, while the liability limit for offshore facilities is the payment of all removal costs plus $75 million per spill damages.  These limits do not apply if the spill is caused by a responsible party’s gross negligence or willful misconduct; the spill resulted from a responsible party’s violation of a federal safety, construction or operating regulation; a responsible party fails to report a spill or to cooperate fully in a cleanup; or a responsible party fails to comply with an order issued under the authority of the Intervention on the High Seas Act.  OPA requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35 million to cover liabilities related to an oil spill for which such responsible party is statutorily responsible.  The President of the United States may increase the amount of financial responsibility required under OPA by up to $150 million, depending on the risk represented by the quantity or quality of oil that is handled by the facility.  Any failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to administrative penalties.  We believe we are in compliance with all applicable OPA financial responsibility obligations.  Moreover, we are not aware of any action or event that would subject us to liability under OPA.

Resource Conservation and Recovery Act.  The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes.  Under the auspices of the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements.  Additionally, various federal, state and local agencies have jurisdiction over transportation, storage and disposal of hazardous waste and seek to regulate movement of hazardous waste in ways not preempted by federal law.  We generate solid and hazardous wastes that are subject to RCRA and comparable state laws.  Drilling fluid, produced water and many other wastes associated with the exploration, development and production of crude oil or natural gas are currently exempt from RCRA’s hazardous waste provisions.  However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be regulated as hazardous waste in the future.  In September 2010, the Natural Resources Defense Council filed a petition with the EPA, requesting it to reconsider the RCRA hazardous waste exemption for exploration, production and development

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wastes.  In December 2016, the court entered a Consent Decree resolving the litigation, under which the EPA would issue such a rulemaking or make a determination that it was not necessary by March 15, 2019.  In response, in April 2019, the EPA issued a determination that rulemaking to address waste from oil and gas exploration and production operations was not necessary at this time.  However, it is possible that the EPA will take up such regulatory changes at a later date.  Any such change in the current RCRA exemption and comparable state laws could result in an increase in the costs to manage and dispose of wastes.  Additionally, these exploration and production wastes will continue to be regulated by state agencies as solid waste.  Also, non-exempt waste streams generated by us will continue to be subject to existing onerous hazardous waste regulations.  Although we do not believe the current costs of managing our wastes (as they are presently classified) to be significant, any repeal or modification of the oil and gas exploration and production exemption by administrative, legislative or judicial process, or modification of similar exemptions in analogous state statutes would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.

Clean Water Act.  The Federal Water Pollution Control Act, or the Clean Water Act, as amended (“CWA”), and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state waters or other waters of the United States.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency.  Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.  In addition, CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

Where required, costs may be associated with the treatment of wastewater and/or the development and implementation of storm water pollution prevention plans.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of CWA and analogous state laws and regulations.  

In addition, the CWA requires permits for discharges of dredged or filled materials into waters of the United States.  These permits (“404 Permits”) are under the joint jurisdiction of the EPA and the Army Corps of Engineers.  404 Permits may be required where development or construction activities have the potential to impact wetland areas that are considered waters of the United States.  In 2020, the EPA revised the definition of waters of the United States to narrow its scope from the 2015 definition that had been promulgated under the Obama administration.  In large part, this rulemaking codified that “waters of the United States” include only those waterbodies (including wetlands) that have a “significant nexus” to navigable waters of the United States.  The rule is currently being challenged and it is expected that the Biden administration will once again look at rulemaking to address the scope of permitting authority under the CWA.  Any expansion of the scope of the CWA could increase costs associated with permitting and regulatory compliance.  However, it is expected that any such change would not disparately affect us and our competitors.

Also, the U.S. Supreme Court in a 2020 case further expanded the reach of the CWA from what had been previously understood.  In this case, the U.S. Supreme Court held that a CWA permit may be required when the addition of pollutants into the waters of the United States is the functional equivalent of a direct discharge into those waters.  This interpretation could increase costs associated with CWA permitting or subject past activities to liability under the CWA.

Air Emissions.  The Federal Clean Air Act, as amended (the “CAA”), and comparable state laws regulate emissions of various air pollutants from various industrial sources through air emissions permitting programs and also impose other monitoring and reporting requirements.  New Source Performance Standards were promulgated for the oil and gas industry in 2012.  These standards set limits for sulfur dioxide and volatile organic compound emissions and required application of reduced emission completion techniques by the industry.  We may be required to incur certain capital or operating expenditures in the future for air pollution control equipment in connection with obtaining and maintaining pre-construction and operating permits and approvals for air emissions.  In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.  Federal and state regulatory agencies can impose penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

In May 2016, the EPA issued a final rule regulating methane emissions from oil and natural gas operations (the “Subpart OOOOa Rule”).  This rule applies to emissions from new, reconstructed and modified processes and equipment and also requires owners and operators to find and repair leaks to address fugitive emissions.  However, in August 2020, the EPA enacted an amendment to the Subpart OOOOa Rule, which removes all methane-specific requirements from production and processing segments and removes VOC and methane emission standards from transmission and storage facilities.

Certain states have also adopted, or are considering, regulations addressing methane releases from oil and gas operations.  Colorado has adopted regulations reducing methane emissions from oil and gas operations.  Compliance with rules applicable to jurisdictions in which we operate could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.  

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Hydraulic Fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight rock formations.  The process involves the injection of mainly water and sand plus a de minimis amount of chemicals under pressure into formations to fracture the surrounding rock and stimulate production.  We expect that we will utilize hydraulic fracturing for the foreseeable future to complete or recomplete wells in areas in which we work.  Hydraulic fracturing is typically regulated at the state level; however, the EPA issued guidance in 2014 to address hydraulic fracturing injections using diesel.

In addition, in June 2016, the EPA issued a final rule promulgating pretreatment standards for discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works.  The EPA, along with other federal agencies such as the U.S. Department of Energy, the U.S. Government Accountability Office, the U.S. Department of Interior and the White House Council for Environmental Quality continue to study various aspects of hydraulic fracturing.  

In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.  Multiple states, including Texas, Colorado and Wyoming have already adopted rules requiring disclosures of chemicals used in hydraulic fracturing and others have enacted regulations imposing additional requirements on activities involving hydraulic fracturing.  Chemical disclosure regulations may increase compliance costs and may limit our ability to use cutting-edge technology in markets where disclosure is required.  Further, laws such as those restricting the use of or regulating the time, place and manner of hydraulic fracturing (such as setback ordinances) may impact our ability to fully extract reserves.  As an example of state governmental actions, the Colorado Oil and Gas Conservation Commission (“COGCC”) has adopted new regulations that will impose, as of January 2021, siting requirements or “setbacks” on certain oil and gas drilling locations based on the distance of a proposed well pad to occupied structures.  Pursuant to the regulations, well pads cannot be located within 500 feet of an occupied structure without the consent of the property owner.  As part of the permitting process, the COGCC will consider a series of siting requirements for all drilling locations located between 500 feet and 2,000 feet of an occupied structure.  Alternatively, the operator may seek a waiver from each owner and tenant within the designated distance.  We are currently evaluating the impact of these regulations on our business.  At this time, we do not anticipate near-term changes to our development program in the DJ Basin based on these regulations.  We may, however, experience increased costs to comply with such requirements or delays or curtailment in permitting, impacting our development or production activities.  Such delays, curtailments, limitations, or prohibitions, if determined to be significant, could have a material adverse effect on our future cash flows and results of operations and may negatively impact our reportable quantities of proved undeveloped oil and gas reserves.  No assurance can be given as to whether or not such measures might be adopted in additional jurisdictions in which our properties are located.  If new laws, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where our properties are located, such legal requirements could prohibit or make it more difficult or costly for us to perform hydraulic fracturing activities.

Further, in May 2014, the EPA published an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act, relating to the disclosure of chemical substances and mixtures used in oil and gas exploration and production.  On July 11, 2014, the EPA extended the public comment period for the rulemaking to September 18, 2014.  The EPA has not yet taken further action with respect to this rule.  Depending on the precise disclosure requirements the EPA elects to impose, if any, we may be obliged to disclose valuable proprietary information, and failure to do so may subject us to penalties.  In addition, we may be required to disclose information of third parties, that may be inaccurate or that we may be contractually prohibited from disclosing, which could also subject us to penalties.

In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008.  This study, as well as subsequent studies and reports, may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells.  If such new laws or rules are adopted, our operations may be curtailed while alternative treatment and disposal methods are developed and approved.

Global Warming and Climate Change.  In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes.  Based on these findings, the EPA has adopted and implemented regulations that restrict emissions of GHG under existing provisions of the CAA.

At present, the EPA may establish GHG permitting requirements for stationary sources already subject to the Prevention of Significant Deterioration (“PSD”) and Title V requirements of the CAA.  Certain of our equipment and installations may currently be subject to PSD and Title V requirements and hence, under the U.S. Supreme Court’s ruling, may also be subject to the installation of controls to capture GHGs.  For any equipment or installation so subject, we may have to incur increased compliance costs to capture related GHG emissions.

In October 2016, the EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements.  The public comment period for the rulemaking concluded on December 16, 2016.  While no final rule has been published, this may be taken up as a priority by the Biden administration.

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In August 2015, the EPA issued a rule to reduce carbon emissions from electric generating units.  The rule, commonly called the “Clean Power Plan,” required states to develop plans to reduce carbon emissions from fossil fuel-fired generating units commencing in 2022, with the reductions to be fully phased in by 2030.  However, in February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it was being challenged in court.  On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan and on August 18, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule as a replacement to the Clean Power Plan.  The EPA issued the final ACE rule in June 2019.  As expected, over 20 states and public health and environmental organizations challenged the rule and it was vacated on January 29, 2021.  The matter has been remanded to the EPA and it is expected that the Biden administration will propose new rules in this area during the next four years.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHG, and many states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, GHG permitting and/or regional GHG “cap and trade” programs.  Most of these “cap and trade” programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.  Also, in recent years, lawsuits have been brought against other energy companies for matters relating to climate change.  Multiple states and localities have also initiated investigations in climate-change related matters.  While the current suits focus on a variety of issues, at their core they seek compensation for the effects of climate change from companies with ties to GHG emissions.  It is currently unknown what the outcome of these types of actions may be, but the costs of defending against such actions may be expected to rise.  Finally, it should be noted that many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.  If any such effects were to occur, they could have a material adverse effect on our assets and operations.

Consideration of Environmental Issues in Connection with Governmental Approvals.  Our operations frequently require licenses, permits and/or other governmental approvals.  Several federal statutes, including the Outer Continental Shelf Lands Act (“OCSLA”), the National Environmental Policy Act (“NEPA”) and the Coastal Zone Management Act (“CZMA”), require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions.  OCSLA, for instance, requires the U.S. Department of Interior to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment.  Similarly, NEPA requires the U.S. Department of Interior and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment.  In the course of such evaluations, an agency would have to prepare an environmental assessment and potentially an environmental impact statement.  Recent federal court cases involving natural gas pipelines have involved challenges to the sufficiency of the evaluation of climate change impacts in environmental impact statements prepared under NEPA.  The CZMA, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and gas development.  In obtaining various approvals from the U.S. Department of Interior, we must certify that we will conduct our activities in a manner consistent with all applicable regulations.

Available Information

We maintain a website at the address www.whiting.com.  We are not including the information contained on our website as part of, or incorporating it by reference into, this report.  We make available free of charge (other than an investor’s own Internet access charges) through our website our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, including exhibits and amendments to these reports, as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC.

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Item 1A.      Risk Factors

Each of the risks described below should be carefully considered, together with all of the other information contained in this Annual Report on Form 10-K, before making an investment decision with respect to our securities.  In the event of the occurrence, reoccurrence, continuation or increased severity of any of the risks described below, our business, financial condition or results of operations could be materially and adversely affected, and you may lose all or part of your investment.

Summary Risk Factors

The following is a summary of the material risks and uncertainties we have identified, which should be read in conjunction with the more detailed description of each risk factor contained below.

Risks Related to Our Recent Emergence from Chapter 11 Bankruptcy

Risks Related to Our Business and Operations

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Risks Related to Our Capital Structure and Financial Results

Risks Related to Investor Sentiment, Corporate Governance, Legal Proceedings and Government Regulation

Risks Related to Our Recent Emergence from Chapter 11 Bankruptcy

We recently emerged from bankruptcy, which may adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the voluntary cases under chapter 11 of the Bankruptcy Code (the “Chapter 11 Cases”) may adversely affect our business and relationships with customers, vendors, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:

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The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation.  We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of our chapter 11 plan of reorganization (the “Plan”) and the transactions contemplated thereby.

In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from the Chapter 11 Cases on September 1, 2020 (the “Emergence Date”).  Those projections were prepared solely for the purpose of bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors.  At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize.  Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects.  Actual results may vary significantly from those contemplated by the projections.  As a result, investors should not rely on these projections.

Our historical financial information may not be indicative of future financial performance.

Our capital structure was significantly impacted by the Plan.  Under fresh start accounting rules that applied to us upon the Emergence Date, assets and liabilities were adjusted to fair values.  Accordingly, because fresh start accounting rules applied, our financial condition and results of operations following emergence from the Chapter 11 Cases will not be comparable to the financial condition and results of operations reflected in our historical financial statements.

The market price of our securities is subject to volatility.

Upon our emergence from the Chapter 11 Cases, our old common stock was cancelled and we issued new common stock.  The market price of our new common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our new common stock may be affected by, numerous factors, many of which are beyond our control.  These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Item 1A of this Annual Report on Form 10-K.

The exercise of all or any number of outstanding Warrants, the issuance of stock-based awards or the issuance of our common stock to settle the claims of general unsecured claimants may dilute your holding of shares of our common stock.

As of the date of filing this report, we have outstanding Warrants (as defined in the “Shareholders’ Equity” footnote in the notes to the consolidated financial statements under the heading “Warrants,” which is incorporated herein by reference) to purchase approximately 7.3 million shares of our common stock at average exercise prices of either $73.44 or $83.45 per share.  In addition, as of December 31, 2020, approximately 3.8 million shares of our common stock remained available for grant under the Whiting Petroleum Corporation 2020 Equity Incentive Plan.  We also reserved approximately 3.0 million shares of our common stock for potential future distribution to certain general unsecured claimants for claims pending resolution in the Bankruptcy Court (including, without limitation, for potential claims relating to the contracts at issue in the matter Arguello Inc. and Freeport-McMoRan Oil & Gas LLC described in the “Commitments and Contingencies” footnote in the notes to the consolidated financial statements).  In February 2021, we issued 948,897 shares out of this reserve to a general unsecured claimant in full settlement of such claimant’s claims pending before the Bankruptcy Court and for rejection damages relating to an executory contract.  Refer to the “Subsequent Event” footnote in the notes to the consolidated financial statements for more information.  The exercise of the Warrants, the issuance or exercise of equity awards that we may grant in the future, the issuance of our common stock to general unsecured claimants or the sale of shares of our common stock issued pursuant to any of the foregoing could have a material adverse effect on the market for our common stock, including the price that an investor could obtain for their shares.

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The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from the Chapter 11 Cases.

The success of our business depends on key personnel.  The ability to attract and retain these key personnel may be difficult in light of our emergence from the Chapter 11 Cases, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances.  We may need to enter into retention or other arrangements that could be costly to maintain.  If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

Risks Related to Our Business and Operations

Oil and natural gas prices are very volatile.  An extended period of low oil and natural gas prices may adversely affect our business, financial condition, results of operations or cash flows.

The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices.  The price we receive for our oil, NGL and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth.  The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to, the following:

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These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements.  Also, prices for crude oil and prices for natural gas do not necessarily move in tandem.  Declines in oil or natural gas prices would not only reduce revenue, but could also reduce the amount of oil and natural gas that we can economically produce and therefore potentially lower our oil and gas reserve quantities.  If the oil and natural gas industry experiences extended periods of low prices, we may, among other things, be unable to meet all of our financial obligations or make planned expenditures.

Oil prices declined sharply during 2020 primarily in response to Saudi Arabia’s announcement of plans to abandon previously agreed upon output restraints and the economic effects of the COVID-19 pandemic on the demand for oil and natural gas.  Substantial and extended declines in oil, NGL and natural gas prices have resulted and may continue to result in impairments of our proved oil and gas properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures.  To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we will be required to reduce spending, borrow under the Exit Credit Agreement or sell assets.  Lower commodity prices may reduce the amount of our borrowing base under the Exit Credit Agreement, which is determined at the discretion of our lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular redeterminations on April 1 and October 1 of each year, as well as special redeterminations described in the Exit Credit Agreement.  Upon a redetermination, if total outstanding credit exposure exceeds the redetermined borrowing base, we could be forced to repay borrowings under the Exit Credit Agreement.

Lower commodity prices may also make it more difficult for us to comply with the covenants and other restrictions in the agreements governing our debt as described under the Risk Factor entitled “The Exit Credit Agreement contains various covenants limiting the discretion of our management in operating our business.”

Alternatively, higher oil, NGL and natural gas prices may result in significant mark-to-market losses being incurred on our commodity-based derivatives, which may in turn cause us to experience net losses.

The occurrence of epidemic or pandemic diseases, including the COVID-19 pandemic, could adversely affect our business, financial condition, results of operations and cash flows.

Global or national health concerns, including the outbreak of pandemic or contagious disease, can negatively impact the global economy and, therefore, demand and pricing for oil and natural gas products.  For example, the World Health Organization declared COVID-19 a pandemic in March 2020, and the continued duration and severity of the COVID-19 pandemic and its ongoing impact on our business cannot be predicted.  The outbreak of communicable diseases, or the perception that such an outbreak could occur, could result in a widespread public health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that would negatively impact the demand for oil and natural gas products.  Furthermore, uncertainty regarding the impact and length of any outbreak of pandemic or contagious disease, including COVID-19, could lead to increased volatility in oil and natural gas prices.  The occurrence or continuation of any of these events could lead to decreased revenues and limit our ability to execute on our business plan, which could adversely affect our business, financial condition, results of operations and cash flows.

Additionally, in response to the COVID-19 pandemic, many of our corporate staff have been working remotely and many of our key vendors, service suppliers and partners have similarly been working remotely.  As a result of such remote work arrangements, certain operational, reporting, accounting and other processes may slow, which could result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies.  In the event that there is an outbreak of COVID-19 at any of our operating locations, we could be forced to cease operations at such location.  Any of the foregoing could adversely affect our business, financial condition, results of operations and cash flows.

The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market.  Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing.  For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices.  In March 2020, members of OPEC and Russia considered extending and potentially increasing these oil production cuts.  However, those negotiations were unsuccessful.  As a result, Saudi Arabia announced an immediate reduction in export prices and Russia announced that all previously agreed upon oil production cuts would expire on April 1, 2020.  These actions led to an immediate and steep decrease in oil prices, which reached a closing NYMEX price low of under negative $37.00 per Bbl of crude oil in April 2020.  Although OPEC members subsequently agreed on certain production cuts beginning in May 2020 and continuing through

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April 2022, in December 2020 OPEC members agreed to minor production increases beginning January 2021 and to reassess production targets each subsequent month.  There can be no assurance that OPEC members and other oil exporting nations will continue to agree to future production cuts, moderating future production or other actions to support and stabilize oil prices, nor can there be any assurance that they will not further reduce oil prices or increase production.  Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could adversely affect our business, financial condition, results of operations and cash flows.

We transport a portion of our crude oil through the DAPL, which is subject to ongoing litigation that may result in a shutdown of the DAPL, which could adversely affect our business, financial condition, results of operations or cash flows.

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On March 25, 2020, the U.S. District Court for D.C. (“D.C. District Court”) found that the U.S. Army Corps of Engineers had violated the National Environmental Policy Act when it granted an easement relating to a portion of the DAPL because it had failed to prepare an environmental impact statement.  As a result, in an order issued July 6, 2020, the D.C. District Court vacated the easement and directed that the DAPL be shut down and emptied of oil by August 5, 2020.  On August 5, 2020, the U.S. Court of Appeals for the D.C. Circuit (“D.C. Appellate Court”) granted a stay of the portion of the order directing the shutdown of the DAPL.  The stay allowed the DAPL to continue to operate until a further ruling was made.  On January 26, 2021, the D.C. Appellate Court affirmed the D.C. District Court’s decision to vacate the easement and concluded that the D.C. District Court must further consider whether shut down of the DAPL is an appropriate remedy while the U.S. Army Corps of Engineers develops an environmental impact statement.  We cannot provide any assurance as to the ultimate outcome of the litigation, and it is possible the DAPL may be required to be shut down as a result of such litigation.  The disruption of transportation as a result of the DAPL being shut down or the anticipation of DAPL being shut down could negatively impact our ability to achieve the most favorable prices for our crude oil production, which could have an adverse effect on our business, financial condition, results of operations or cash flows.  While we are coordinating with our midstream partners and downstream markets to source transportation alternatives in order to mitigate the impact of a DAPL shutdown, we cannot provide any assurance that our efforts to do so will be successful.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition, results of operations or cash flows.

Our future success will depend on the success of our development and production activities.  Our oil and natural gas development activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production.  Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.  Refer to the Risk Factor entitled “Reserve estimates depend on many assumptions that may turn out to be inaccurate...” for a discussion of the uncertainty involved in these processes.  Our cost of drilling, completing and operating wells is often uncertain before drilling commences.  Overruns in budgeted expenditures are common risks that can make a particular project uneconomical.  Further, many factors may curtail, delay or cancel drilling, including, but not limited to, the following:

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Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and a failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our business, financial condition, results of operations or cash flows.

Our future growth prospects are dependent upon our ability to identify optimal strategies for investing our capital resources to produce favorable rates of return.  In developing our business plan, we consider allocating capital and other resources to various aspects of our business including well development (primarily drilling), reserve acquisitions, corporate items and other alternatives.  We also consider our likely sources of capital, including cash generated from operations and borrowings under the Exit Credit Agreement.  Notwithstanding the determinations made in the development of our business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions.  If we fail to identify optimal business strategies or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and future growth may be adversely affected.  Moreover, economic or other circumstances may change from those contemplated by our business plan and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, we may not be able to sustain production.

Unless we conduct successful development and production activities or acquire properties containing proved reserves, our proved reserves will decline over time.  Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors.  Our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and producing our current reserves and finding economically recoverable or acquiring additional economically recoverable reserves.  In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources to acquire attractive companies or properties.  Therefore, we may not be able to develop, find or acquire additional reserves to sustain or replace our current and future production, which could adversely affect our business, financial condition, results of operations or cash flows.

A large portion of our producing properties are concentrated in the Williston Basin of North Dakota and Montana, making us vulnerable to risks associated with operating in one major geographic area.

A large portion of our producing properties are geographically concentrated in the Williston Basin of North Dakota and Montana.  At December 31, 2020, approximately 94% of our total estimated proved reserves were attributable to properties located in this area.  Because of this concentration in a limited geographic area, the success and profitability of our operations may be disproportionately exposed to regional factors compared to competitors having more geographically dispersed operations.  These factors include, among others: (i) the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints, (ii) the availability of rigs, equipment, oilfield services, supplies and labor, (iii) the availability of processing and refining facilities and (iv) infrastructure capacity.  In addition, our operations in the Williston Basin may be adversely affected by severe weather events such as floods, blizzards, ice storms, tornadoes and freezing temperatures which can intensify competition for the items and services described above and may result in periodic shortages.  The concentration of our operations in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic events (which may result in third-party lawsuits), industrial accidents, labor difficulties, civil disturbances, public protests or terrorist attacks.  Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration.  Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations and cash flows.  

Market conditions or operational impediments may hinder our access to oil and gas markets or delay our production.

In connection with our continued development of oil and gas properties, we are exposed to the impact of delays or interruptions of production from wells on these properties, caused by transportation capacity constraints, curtailment of production or the interruption of transporting oil and gas volumes produced.  In addition, market conditions or a lack of satisfactory oil and gas transportation arrangements may hinder our access to oil and gas markets or delay our production.  The availability of a ready market for our oil, NGL and natural gas production depends on a number of factors, including the demand for and supply of oil, NGLs and natural gas, downstream market conditions and competing supply alternatives.  Our ability to market our production also depends substantially on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties and the ability to obtain such services on acceptable terms.  We may be disproportionately exposed to the impact of delays or interruptions of production caused by market constraints or the interruption of transporting oil and gas produced.  This could lead to production curtailments or shut-ins, and reduced revenue which could materially harm our business.  We may enter into arrangements for transportation services and sales to reduce curtailment risks.  However, these services expose us to the risk that third parties will default on their obligations under such arrangements.  

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Risks associated with the production, gathering, transportation and sale of oil, NGLs and natural gas could materially and adversely affect our business, financial condition, results of operations or cash flows.

Our financial condition, net income and cash flows will depend upon, among other things, oil, NGL and natural gas production and the prices received and costs incurred to develop and produce oil and natural gas reserves.  Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, NGLs and natural gas will decrease revenues and increase expenditures.  For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages.  Any costs incurred in connection with any such accidents that are not insured against will have the effect of reducing net income.  We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations.  Also, our oil, NGL and natural gas production depends in large part on the proximity and capacity of pipeline systems and transportation facilities which are mostly owned by third parties.  The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans.  Similarly, curtailments or damage to pipelines and other transportation facilities used to transport oil, NGL and natural gas production to markets for sale could decrease revenues or increase transportation expenses.  Any such curtailments or damage to the gathering systems could also require finding alternative means to transport oil, NGL and natural gas production, which alternative means could result in additional costs that will have the effect of increasing transportation expenses or differentials.  Adverse changes in the terms and conditions of natural gas pipeline tariffs could result in increased costs or competitive disadvantages.

Also, accidents involving rail cars could result in significant personal injuries and property and environmental damage.  In May 2015, the Pipeline and Hazardous Material Safety Administration issued new rules applicable to “high-hazard flammable trains”, discussed in “Item 1 Business – Regulation – Regulation of Sale and Transportation of Oil” above, which could increase transportation expenses.  Similarly, regulatory responses to the October 2015 failure at a Southern California underground natural gas storage facility could also lead to increased expenses for underground storage.

In addition, drilling, production and transportation of hydrocarbons bear the inherent risk of loss of containment.  Potential consequences include, but are not limited to, loss of reserves, loss of production, loss of economic value associated with the affected wellbore, personal injuries and death, contamination of air, soil, ground water and surface water, as well as potential fines, penalties or damages associated with any of the foregoing consequences.

Weaker price differentials and/or weaker benchmark prices of oil and natural gas and the wellhead price we receive could have a material adverse effect on our business, financial condition, results of operations or cash flows.

The prices that we receive for our oil and natural gas production generally trade at a discount, but sometimes at a premium, to the relevant benchmark prices such as NYMEX.  A negative or positive difference between the benchmark price and the price received is called a differential.  The differential may vary significantly due to market conditions, the quality and location of production and other risk factors, as demonstrated in the fourth quarter of 2018 when our oil differentials weakened substantially.  We cannot accurately predict oil and natural gas differentials.  Changes in the differential and decreases in the benchmark price for oil and natural gas could have a material adverse effect on our business, financial condition, results of operations or cash flows.

Part of our business strategy includes selling properties which subjects us to various risks.

Part of our business strategy includes selling properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own.  However, there is no assurance that such sales will occur in the time frames or with the economic terms we expect.  Unless we conduct successful exploration, development and production activities or acquire properties containing proved reserves, divestitures of our properties will reduce our proved reserves and potentially our production.  We may not be able to develop, find or acquire additional reserves sufficient to replace such reserves and production from any of the properties we sell.  Additionally, agreements pursuant to which we sell properties may include terms that survive closing of the sale, including but not limited to indemnification provisions, which could result in us retaining substantial liabilities.

The unavailability or cost of additional drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis or within our budget.

The demand for qualified and experienced field personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages.  Historically, there have been shortages of drilling rigs, completion crews and other oilfield equipment as demand for these items has increased along with the number of wells being drilled and completed.  These factors also cause significant increases in costs for equipment, services and personnel.  Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs and other oilfield goods and services.  Shortages of field personnel and other professionals, drilling rigs, completion crews, equipment or supplies or price increases could delay or adversely affect our exploration and development operations,

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which could restrict such operations or have a material adverse effect on our business, financial condition, results of operations or cash flows.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

We have specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage.  These scheduled drilling locations represent a significant part of our growth strategy.  Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs of oil field goods and services, drilling results, our ability to extend drilling acreage leases beyond expiration, regulatory approvals and other factors.  Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or gas from these or any other potential drilling locations.  As such, our actual drilling activities may materially differ from those presently identified, which could in turn adversely affect our business, financial condition, results of operations or cash flows or require us to remove certain proved undeveloped reserves from our proved reserve base if we are unable to drill those PUD locations within the SEC’s 5-year window.

Properties that we acquire may not produce as projected, and we may be unable to identify liabilities associated with the properties or obtain indemnities from sellers for liabilities they may have created.

Our business strategy includes a continuing acquisition program.  The successful acquisition of producing properties requires assessment of many factors, which are inherently inexact and may be inaccurate, including, but not limited to, the following:

Furthermore, acquisitions pose substantial risks to our business, financial condition, results of operations and cash flows.  The risks associated with acquisitions, either completed or future acquisitions, include, but are not limited to:

Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies.  In the course of our due diligence, we may not inspect every well, platform, facility or pipeline.  Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination, when they are made.  We may not be able to obtain contractual indemnities from the seller for liabilities that it created.  We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

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Adverse weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and gas operations in the Rocky Mountains are adversely affected by weather conditions and lease stipulations designed to protect various wildlife.  In certain areas, drilling and other oil and gas activities can only be conducted during certain months.  This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages.  Resulting shortages or high costs could delay our operations, cause temporary declines in our oil and gas production and materially increase our operating and capital costs.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and gas operations.

We are not insured against all risks.  Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, results of operations or cash flows.  Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including, but not limited to, the possibility of:

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company.  We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented.  In addition, pollution and environmental risks generally are not fully insurable.  If a significant accident or other event occurs and is not fully covered by insurance, then it could adversely affect us.

We have limited control over activities on properties we do not operate, which could increase capital expenditures.

We operate 91% of our net productive oil and natural gas wells, which represents 94% of our proved developed producing reserves as of December 31, 2020.  If we do not operate the properties in which we own an interest, we do not have control over normal capital expenditures or future development of those properties.  The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s decisions with respect to the timing and amount of capital expenditures, the period of time over which the operator seeks to generate a return on capital expenditures, inclusion of other participants in drilling wells, the use of technology, as well as the operator’s expertise and financial resources and the operator’s relative interest in the field.  Accordingly, while we use reasonable efforts to cause the operator to act in a prudent manner, we are limited in our ability to do so.

We expect to consider from time to time further strategic opportunities that may involve acquisitions, dispositions, investments in joint ventures, partnerships, and other strategic alternatives that may enhance shareholder value, any of which may result in the use of a significant amount of our management resources or significant costs, and we may not be able to fully realize the potential benefit of such transactions.

We expect to continue to consider acquisitions, dispositions, investments in joint ventures, partnerships, and other strategic alternatives with the objective of maximizing shareholder value.  Our board of directors and our management may from time to time be engaged in evaluating potential transactions and other strategic alternatives.  In addition, from time to time, we may engage financial advisors, enter into non-disclosure agreements, conduct discussions, and undertake other actions that may result in one or more transactions.  Although there would be uncertainty that any of these activities or discussions would result in definitive agreements or the completion of any

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transaction, we may devote a significant amount of our management resources to analyzing and pursuing such a transaction, which could negatively impact our operations, and may impair our ability to retain and motivate key personnel.  In addition, we may incur significant costs in connection with seeking such transactions or other strategic alternatives regardless of whether the transaction is completed.  In the event that we consummate an acquisition, disposition, partnership or other or strategic alternative in the future, we cannot be certain that we would fully realize the potential benefit of such a transaction and cannot predict the impact that such strategic transaction might have on our operations or stock price.  Any potential transaction would be dependent upon a number of factors that may be beyond our control, including, among other factors, market conditions, industry trends, regulatory limitations and the interest of third parties in us and our assets.  There can be no assurance that the exploration of strategic alternatives will result in any specific action or transaction.  Further, any such strategic alternative may not ultimately lead to increased shareholder value.  We do not undertake to provide updates or make further comments regarding the evaluation of strategic alternatives, unless otherwise required by law.

Competition in the oil and gas industry and from alternative energy sources is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, obtaining investment capital, securing oilfield goods and services, marketing oil and natural gas products and attracting and retaining qualified personnel.  Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate.  Those companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our resources allow.  Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.  We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

We also face indirect competition from alternative energy sources, including wind, solar, nuclear and electric power.  The proliferation of alternative energy sources and businesses that provide such alternative energy sources may decrease the demand for oil and natural gas products.  Decreased demand for our products could adversely affect our business, financial condition, results of operations or cash flows.

We depend on computer and telecommunications systems, and failures in our systems or cybersecurity attacks could have a material adverse effect on our business, financial condition, results of operations or cash flows.

Our business has become increasingly dependent upon digital technologies to conduct day-to-day operations, including information systems, infrastructure and cloud applications.  We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business.  In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties.  We rely on such systems to process, transmit and securely store electronic information, including financial records and personally identifiable information such as contractor, investor and payroll data, and to manage or support a variety of business processes, including our supply chain, pipeline operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions.  

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also have increased in frequency.  A cyber-attack could include unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites.  It is possible that we could incur interruptions from cybersecurity attacks, computer viruses or malware, or that third-party service providers could cause a breach of our data.  We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls over personally identifiable information and contractor data; however, any interruptions to our arrangements with third parties for our computing and communications infrastructure or any other interruptions to, or breaches of, our information systems could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt our business operations.  

Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future cyber-attacks than other targets.  The various procedures, facilities, infrastructure and controls we utilize to monitor these threats and mitigate our exposure to such threats are costly and labor intensive.  Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring.  We do not expect to obtain or maintain specialized insurance for possible liability or loss resulting from a cyber-attack on our assets that may shut down all or part of our business.  However, as cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.  State and federal cybersecurity legislation could also impose new requirements, which could increase our cost of doing business.  

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To our knowledge we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer material losses in the future either as a result of an interruption to or a breach of our systems or those of our third-party vendors and service providers.  A cyber incident involving our information systems and related infrastructure, or that of third parties, could disrupt our business plans and negatively impact our operations in the following ways, among others, any of which could have a material adverse effect on our reputation, business, financial condition, results of operations or cash flows:

Risks Related to Our Capital Structure and Financial Results

The Exit Credit Agreement contains various covenants limiting the discretion of our management in operating our business.

The Exit Credit Agreement contains various restrictive covenants that may limit our management’s discretion in certain respects.  In particular, this agreement limits our and our subsidiaries’ ability to, among other things:

The Exit Credit Agreement requires us, as of the last day of any quarter to maintain commodity hedges covering a minimum of 65% of our projected production for the succeeding twelve months, and 35% of our projected production for the next succeeding twelve months, both as reflected in our most recent delivered proved reserves projection.  We are also limited to hedging a maximum of 85% of our production from proved reserves.  In addition, the Exit Credit Agreement requires us, as of the last day of any quarter beginning with the quarter ending December 31, 2020, to maintain the following ratios (as defined in the Exit Credit Agreement): (i) a consolidated current assets to consolidated current liabilities ratio of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio

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of not greater than 3.5 to 1.0.  Factors that may adversely affect our ability to comply with these covenants include oil or natural gas price declines, lack of liquidity in property and capital markets and our inability to execute on our development plan.

Moreover, the borrowing base limitation on the Exit Credit Agreement is redetermined on April 1 and October 1 of each year, and may be the subject of special redeterminations described in the Exit Credit Agreement based on an evaluation of our oil and gas reserves.  Because oil and gas prices are principal inputs into the valuation of our reserves, if oil and gas prices decline, our borrowing base could be reduced at the next redetermination date or during future redeterminations.  Upon a redetermination, if total outstanding credit exposure exceeds the redetermined borrowing base, we will be required to prepay outstanding borrowings under the Exit Credit Agreement.

Our debt level and the covenants in the Exit Credit Agreement could negatively impact our financial condition, results of operations, cash flows and business prospects.

As of December 31, 2020, we had $360 million of borrowings and $2 million in letters of credit outstanding under the Exit Credit Agreement with $388 million of available borrowing capacity.  The Exit Credit Agreement matures on April 1, 2024.  We are allowed to incur additional indebtedness, provided that we meet certain requirements in the Exit Credit Agreement.

Our level of indebtedness and the covenants contained in the agreements governing our debt could have important consequences for our operations, including, but not limited to:

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances.  If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of our repayment of outstanding debt.  Refer to the Risk Factor entitled “The Exit Credit Agreement contains various covenants limiting the discretion of our management in operating our business.”

Our development operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and gas industry is capital intensive.  We make and expect to continue to make substantial capital expenditures in our business and operations for the development, production and acquisition of oil and natural gas reserves.  To date, we have financed capital expenditures through a combination of internally generated cash flows, equity and debt issuances, bank borrowings, agreements with industry partners and oil and gas property divestments.  We intend to finance future capital expenditures substantially with cash flow

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from operations, cash on hand and borrowings under the Exit Credit Agreement.  Our cash flow from operations and access to capital is subject to a number of variables, including, but not limited to:

If our revenues or the borrowing base under the Exit Credit Agreement decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves, or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels.

We may, from time to time, need to seek additional financing.  There can be no assurance as to the availability or terms of any additional financing.  Disruptions in the capital and credit markets, particularly in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow.  If cash generated by operations or availability under the Exit Credit Agreement is not sufficient to meet our capital requirements, the inability to access the cash and credit markets to obtain additional financing, on favorable terms or otherwise, could result in a curtailment of our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves.

If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.

Our earnings and cash flow could vary significantly from year to year due to the volatility of oil and natural gas prices.  As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods.  Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments.  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 service our debt.  Factors that may cause us to generate cash flow that is insufficient to meet our debt obligations include the events and risks related to our business, many of which are beyond our control.  Any cash flow insufficiency would have a material adverse impact on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.  If we do not generate sufficient cash flow from operations to service our outstanding indebtedness, we may be required to undertake various alternative financing plans, which may include:

We cannot assure you that we would be able to implement any of the above alternative financing plans, if necessary, on commercially reasonable terms or at all.  If we cannot make scheduled payments on our indebtedness or otherwise fail to comply with the covenants and other restrictions in the agreements governing our debt, we will be in default and the lenders under the Exit Credit Agreement could declare all outstanding principal and interest to be due and payable.  Additionally, the lenders under the Exit Credit Agreement could terminate their commitments to loan money and could foreclose against our assets collateralizing our borrowings, and we could be forced into bankruptcy or liquidation.  If the amounts outstanding under our Exit Credit Agreement were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to the lenders.  Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms or at all, would materially and adversely affect our business, financial position, results of operations and cash flows.

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Reserve estimates depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex.  It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors.  Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves referred to in this Annual Report on Form 10-K.

In order to prepare our estimates, we must project production rates and timing of development expenditures.  We must also analyze available geological, geophysical, production and engineering data.  The extent, quality and reliability of this data can vary.  The process also requires economic assumptions about matters such as the following, among others:

Therefore, estimates of oil and natural gas reserves are inherently imprecise.  Actual future production, oil, NGL and natural gas prices, revenues, taxes, exploration and development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates.  Any significant variance could materially affect the estimated quantities and present value of reserves referred to in this Annual Report on Form 10-K.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our proved reserves, as referred to in this report, is the current market value of our estimated proved oil and natural gas reserves.  In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on 12-month average prices and current costs as of the date of the estimate.  The 12-month average prices used for the year ended December 31, 2020 were $39.57 per Bbl of oil and $1.99 per MMBtu of natural gas.  Actual future prices and costs may differ materially from those used in the estimate.  If the 12-month average oil prices used to calculate our oil reserves decline by $1.00 per Bbl, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2020 would have decreased by $80 million.  If the 12-month average natural gas prices used to calculate our natural gas reserves decline by $0.10 per MMBtu, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2020 would have decreased by $16 million.

Our use of oil and natural gas price hedging contracts involves only a portion of our anticipated production, may limit higher revenues in the future in connection with commodity price increases and may result in significant fluctuations in our net income.

We enter into hedging transactions of our oil and natural gas production revenues to reduce our exposure to fluctuations in the price of oil and natural gas.  Our hedging transactions to date have consisted of financially settled crude oil and natural gas options contracts, primarily costless collars and swaps, placed with major financial institutions.  As of February 24, 2021, we had crude oil derivative contracts covering the sale of 38,000 Bbl, 25,000 Bbl and 22,000 Bbl of oil per day for the remainder of 2021, 2022 and the first three months of 2023, respectively.  Additionally, we had natural gas derivative contracts covering the sale of 82,000 MMBtu, 39,000 MMBtu and 20,000 MMBtu of natural gas per day through the remainder of 2021, 2022 and the first three months of 2023, respectively.  Finally, we have basis swap contracts covering the sale of 20,000 MMBtu per day through the remainder of 2021 that are settled on the difference between the Northern Natural Gas Ventura index price and NYMEX Henry Hub.  Refer to “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A and the “Derivative Financial Instruments” footnote of the consolidated financial statements in Item 8 of this Annual Report on Form 10-K for pricing information and a more detailed discussion of our hedging transactions.

We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas, or alternatively, we may decide to unwind or restructure the hedging arrangements we previously entered into.  Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.  Hedging transactions may limit the benefit we may otherwise receive from increases in the price for oil and natural gas.  Furthermore, although we are required under the terms of the Exit Credit Agreement to engage in hedging transactions, if we do not engage in hedging transactions or unwind hedging transactions we previously entered into, then we may be more adversely affected by declines in oil and natural gas prices than our competitors who engage in hedging transactions.  Additionally, hedging transactions may expose us to cash margin requirements.

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We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive income (loss).  Consequently, we may experience significant net losses, on a non-cash basis, due to changes in the value of our hedges as a result of commodity price volatility.

Also, in 2010, the U.S. Congress adopted the Dodd-Frank Act, which, among other provisions, established federal oversight and regulation of the over-the-counter derivatives market.  If we do not qualify for an end user exemption from the Dodd-Frank Act requirements, the regulations could increase the cost of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, lead to fewer potential counterparties, and increase our exposure to less creditworthy counterparties, any of which could limit our desire and ability to implement commodity price risk management strategies.  If our use of derivatives becomes limited as a result of the regulations, our results of operations may become more volatile and our cash flows may be less predictable.  Certain aspects of the Dodd-Frank rulemaking have been repealed or have not been finalized and the ultimate effect of the regulations on our business remains uncertain.

Our ability to use our NOLs in future periods may be limited.  

As of December 31, 2020, we had U.S. federal NOLs of $3.1 billion, the majority of which will expire between 2022 and 2037, if not limited by triggering events prior to such time.  Under the provisions of the Internal Revenue Code (“IRC”), changes in our ownership, in certain circumstances, will limit the amount of U.S. federal NOLs that can be utilized annually in the future to offset taxable income.  In particular, Section 382 of the IRC imposes limitations on a company’s ability to use NOLs upon certain changes in such ownership.  As a result of the chapter 11 reorganization and related transactions, we experienced an ownership change within the meaning of IRC Section 382 that subjected certain of our tax attributes, including NOLs, to an IRC Section 382 limitation.  Calculations pursuant to Section 382 of the IRC can be very complicated and no assurance can be given that upon further analysis, our ability to take advantage of our NOLs may be limited to a greater extent than we currently anticipate.  If we are limited in our ability to use our NOLs in future years in which we have taxable income, we will pay more taxes than if we were able to utilize our NOLs fully, which could have a negative impact on our financial position and results of operations.  Additionally, we may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in further limitations being placed on our ability to utilize our federal NOLs.

If oil, NGL and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and gas properties.

Accounting rules require that we periodically review the carrying value of our producing oil and gas properties for possible impairment.  Based on specific market factors and circumstances at the time of prospective impairment reviews (which may include depressed oil, NGL and natural gas prices and the continuing evaluation of development plans, production data, economics, possible asset sales and other factors) we may be required to write down the carrying value of our oil and gas properties.  For example, we recorded a $4.1 billion in impairment charges during 2020 for the partial write-downs of our Williston Basin resource play.  A write-down constitutes a non-cash charge to earnings.  We may incur additional impairment charges in the future, which could have a material adverse effect on our business, financial condition, results of operations or cash flows in the period recognized.

We may continue to incur cash and noncash charges that would negatively impact our future results of operations and liquidity.

While executing our strategic priorities to reduce financial leverage and complexity and to lower our capital expenditures in the face of lower commodity prices, we have incurred certain cash charges.  As we continue to focus on our strategic priorities, we may incur additional cash and noncash charges in the future.  If incurred, these charges could have a material adverse effect on our liquidity and results of operations in the period recognized.

Risks Related to Investor Sentiment, Corporate Governance, Legal Proceedings and Government Regulation

A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital.

Certain segments of the investor community have developed negative sentiment towards investing in our industry.  Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices.  In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations.  Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects.

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Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.  Refer to the Risk Factor entitled “Negative public perception regarding us and/or our industry could have a material adverse effect on our business, financial condition, results of operations and cash flows.”

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight rock formations.  The process involves the injection of mainly water and sand plus a de minimis amount of chemicals under pressure into formations to fracture the surrounding rock and stimulate production.  We expect that we will utilize hydraulic fracturing for the foreseeable future to complete or recomplete wells in the areas in which we work.  Hydraulic fracturing is typically regulated at the state level, however, the U.S. Environmental Protection Agency (the “EPA”) issued guidance in 2014 to address hydraulic fracturing injections involving diesel.  In addition, in June 2016, the EPA issued a final rule promulgating pretreatment standards for discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works.  The EPA, along with other federal agencies such as the U.S. Department of Energy, the U.S. Government Accountability Office, the U.S. Department of Interior and the White House Council for Environmental Quality continue to study various aspects of hydraulic fracturing.

In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.  Multiple states, including Texas, Colorado and Wyoming have already adopted rules requiring disclosures of chemicals used in hydraulic fracturing and others have enacted regulations imposing additional requirements on activities involving hydraulic fracturing.  Chemical disclosure regulations may increase compliance costs and may limit our ability to use cutting-edge technology in markets where disclosure is required.  Further, laws such as those restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing (such as setback ordinances) may impact our ability to fully extract reserves.  Refer to the Risk Factor entitled “The enactment of Colorado Senate Bill 19-181 ‘Protect Public Welfare Oil And Gas Operations’ increased the regulatory authority of local governments in Colorado…” for specific regulations currently impacting Whiting.  No assurance can be given as to whether or not additional measures might be considered or implemented in the jurisdictions in which our properties are located.  If new laws, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where our properties are located, such legal requirements could prohibit or make it more difficult or costly for us to perform hydraulic fracturing activities.

Further, in May 2014, the EPA published an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act, relating to the disclosure of chemical substances and mixtures used in oil and gas exploration and production.  On July 11, 2014, the EPA extended the public comment period for the rulemaking to September 18, 2014.  The EPA has not yet taken further action with respect to this rule.  Depending on the precise disclosure requirements the EPA elects to impose, if any, we may be obliged to disclose valuable proprietary information, and failure to do so may subject us to penalties.  In addition, we may be required to disclose information of third parties, which may be inaccurate or which we may be contractually prohibited from disclosing, which could also subject us to penalties.

In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008.  This study, as well as subsequent studies and reports, may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells.  If such new laws or rules are adopted, our operations may be curtailed while alternative treatment and disposal methods are developed and approved.

Refer to “Hydraulic Fracturing” in Item 2 of this Annual Report on Form 10-K for more information on hydraulic fracturing.

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The Biden administration, acting through the executive branch and/or in coordination with Congress, could enact rules and regulations that impose more onerous permitting and other costly environmental, health and safety requirements.

During the campaign, President Biden stated that, if elected President, he would issue Executive Orders to permanently protect certain federal lands, establish monuments, restrict new oil and gas permitting on public lands and waters and modify royalties to account for climate costs.  In January 2021, President Biden signed an Executive Order temporarily suspending oil and gas permitting on federal lands and waters.  In addition, President Biden has indicated that his administration is likely to pursue more stringent methane pollution limits for new and existing oil and gas operations.  These efforts, among others, are intended to support Mr. Biden’s stated goal of addressing climate change.  The potential legislative actions Congress could pursue include imposing more restrictive laws and regulations pertaining to permitting, limitations on greenhouse gas emissions, increased requirements for financial assurance including additional bonding for decommissioning liabilities and carbon taxes.  Any of these administrative or Congressional actions could materially and adversely affect our business, financial condition, results of operations and cash flows 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.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation.  We may be required to make large expenditures to comply with governmental regulations.  Matters subject to regulation include, but are not limited to:

Under these laws, we could be liable for personal injuries, property damage and other damages.  Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and litigation.  Moreover, these laws could change in ways that could substantially increase our costs.  Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition, results of operations or cash flows.  Strict liability or joint and several liability may be imposed under certain laws, which could cause us to become liable for the conduct of others or for consequences of our own actions.  For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.  

Our operations may incur substantial costs and liabilities to comply with environmental laws and regulations.

Our oil and gas operations are subject to stringent federal, state and local laws and regulations relating to the release or discharge of materials into the environment or otherwise relating to environmental protection.  These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentration of materials that can be released into the environment; limit or prohibit drilling or well completion activities on certain lands; and impose substantial liabilities for unauthorized discharges.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations, the imposition of injunctive relief, or certain leases could be cancelled in the event that an agency refuses to issue or delays the issuance of a required permit.  Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previous contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.  Private parties, including the surface owners of properties upon which we drill, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws.  We may not be able to recover some or any of these costs from insurance.  Moreover, federal law and some state laws allow the government to place a lien on real property for costs incurred by the government to address contamination on the property.

Changes in environmental laws and regulations occur frequently and may have a materially adverse impact on our business.  Compliance with any enacted rules could result in significant costs, including increased capital expenditures and operating costs, which may

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adversely impact our business.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance of environmental laws and regulations.

For example, in 2012, the EPA published final rules under the Federal Clean Air Act (the “CAA”) that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants.  With regard to production activities, these rules require, among other things, the reduction of volatile organic compound emissions from certain fractured and refractured gas wells for which well completion operations are conducted and, in particular, requiring some of these wells to use reduced emission completions, also known as “green completions”, after January 1, 2015.  These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers and storage vessels.

In May 2016, the EPA issued a final rule regulating methane emissions from oil and natural gas operations (the “Subpart OOOOa Rule”).

However, in August 2020, the EPA enacted an amendment to the Subpart OOOOa Rule, which removes all methane-specific requirements from production and processing segments and removes VOC and methane emission standards from transmission and storage facilities.  

The enactment of Colorado Senate Bill 19-181 “Protect Public Welfare Oil And Gas Operations” increased the regulatory authority of local governments in Colorado over the surface impacts of oil and gas development, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.

In Colorado, in April 2019, the Colorado Governor signed into law the final version of Senate Bill 19-181 (“SB 181”), known as the “Protect Public Welfare Oil and Gas Operations” legislation.  SB 181 amends the Oil and Gas Conservation Act and other statutes to change the manner in which oil and gas development is regulated in Colorado and provide the opportunity for greater control to local governments.  The amendments include changes to expand the authority of local governments relating to oil and gas development, as well as rulemaking requirements involving the Colorado Oil and Gas Conservation Commission (“COGCC”) and the Air Quality Control Commission (“AQCC”) that could include more stringent air emission limits for pollutants such as methane and volatile organic carbons and more rigorous permitting requirements.  In December 2019, Colorado’s AQCC adopted new rules targeting air emissions from upstream oil and gas operations, and depending on the results of other ongoing and upcoming rulemakings and actions by COGCC, the Colorado Department of Public Health and Environment and local jurisdictions, SB 181 could result in greater restrictions with respect to oil and gas development in Colorado, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.  

With its expanded authority under SB 181, the COGCC has adopted new regulations that will impose, as of January 2021, siting requirements or “setbacks” on certain oil and gas drilling locations based on the distance of a proposed well pad to occupied structures. Pursuant to the regulations, well pads cannot be located within 500 feet of an occupied structure without the consent of the property owner. As part of the permitting process, the COGCC will consider a series of siting requirements for all drilling locations located between 500 feet and 2,000 feet of an occupied structure. Alternatively, the operator may seek a waiver from each owner and tenant within the designated distance.

Efforts similar to SB 181 are likely to continue in the future, which, if successful, could result in dramatically reducing the area available for future oil and gas development or outright banning oil and gas development in certain jurisdictions. We cannot predict the nature or outcome of future ballot initiatives, legislative actions or other similar efforts, or the effects of implementation of these efforts by local governments.  If we are required to cease operating in any of the areas in which we now operate as the result of bans or moratoria on drilling or related oilfield services activities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Issues surrounding climate change and greenhouse gas emissions could result in increased operating costs and reduced demand for oil and gas that we produce.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes.  Based on these findings, the EPA has adopted and implemented regulations that restrict emissions of GHG under existing provisions of the CAA.

At present, the EPA may establish GHG permitting requirements for stationary sources already subject to the Prevention of Significant Deterioration (“PSD”) and Title V requirements of the CAA.  Certain of our equipment and installations may currently be subject to PSD and Title V requirements and hence, under the U.S. Supreme Court’s ruling, may also be subject to the installation of controls to capture GHGs.  For any equipment or installation so subject, we may have to incur increased compliance costs to capture related GHG emissions.

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In October 2016, the EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements.  The public comment period for the rulemaking concluded on December 16, 2016.  While no final rule has been published, this may be taken up as a priority by the Biden presidential administration.

In August 2015, the EPA issued a rule to reduce carbon emissions from electric generating units.  The rule, commonly called the “Clean Power Plan,” requires states to develop plans to reduce carbon emissions from fossil fuel-fired generating units commencing in 2022, with the reductions to be fully phased in by 2030.  However, in February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it was being challenged in court.  On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan and on August 18, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule as a replacement to the Clean Power Plan.  The EPA issued the final ACE rule in June 2019.  As expected, over 20 states and public health and environmental organizations challenged the rule and it was vacated on January 19, 2021.  The matter has been remanded to the EPA and it is expected that the Biden administration will propose new rules in this area during the next four years.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHG, and many states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, GHG permitting and/or regional GHG “cap and trade” programs.  Most of these “cap and trade” programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.  

Also, in recent years, lawsuits have been brought against other energy companies for matters relating to climate change.  Multiple states and localities have also initiated investigations in climate-change related matters.  While the current suits focus on a variety of issues, at their core they seek compensation for the effects of climate change from companies with ties to GHG emissions.  It is currently unknown what the outcome of these types of actions may be, but the costs of defending against such actions may rise.  Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.  If any such effects were to occur, they could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Negative public perception regarding us and/or our industry could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.  Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers.  These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation.  Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts.  Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.

Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities.  Ultimately, this could make it more difficult to secure funding for exploration and production activities.

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A low ESG or sustainability score could result in the exclusion of our common shares from consideration by certain investment funds and a negative perception of us by certain investors.

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Certain organizations that provide corporate governance and other corporate risk information to investors and shareholders have developed scores and ratings to evaluate companies and investment funds based upon environmental, social and governance (“ESG”) or sustainability metrics.  Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders.  Many investment funds focus on positive ESG business practices and sustainability scores when making investments.  In addition, investors, particularly institutional investors, use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance.  Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision.  Consequently, a low sustainability

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score could result in exclusion of our common shares from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of us by certain investors.

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We may be negatively impacted by litigation and legal proceedings, including ongoing claims in connection with the Chapter 11 Cases.

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We are subject from time to time, and in the future may become subject, to litigation claims.  These claims and legal proceedings are typically claims that arise in the normal course of business and include, without limitation, claims relating to environmental, safety and health matters, commercial or contractual disputes with suppliers and customers, claims regarding ownership of mineral interests, including from royalty owners, claims regarding acquisitions and divestitures, regulatory matters and employment and labor matters.  We may also become subject to governmental or regulatory proceedings.  The outcome of such claims and legal proceedings cannot be predicted with certainty and some may be disposed of unfavorably to us.  In addition, the claims resolutions process in connection with the Chapter 11 Cases is ongoing and certain of these claims remain subject to the jurisdiction of the Bankruptcy Court.  To the extent that these legal proceedings result in claims being allowed against us, such general unsecured claims will be satisfied through the issuance of shares of our common stock, except as noted herein.  As a result, we have not established material reserves within our liabilities in connection with these claims.  However, as discussed in more detail in the “Commitments and Contingencies” footnote in the notes to the consolidated financial statements under the heading “Chapter 11 Cases,” it is possible with respect to certain claims that the ultimate outcome of the legal proceedings may result in the contracts not being treated as rejected, certain claims may not be general unsecured claims or the amounts at issue being treated as administrative claims by the Bankruptcy Court (including, without limitation, the matter relating to Arguello Inc. and Freeport-McMoRan Oil & Gas LLC described in the “Commitments and Contingencies” footnote in the notes to the consolidated financial statements), any of which could require us to make cash payments to resolve claims instead of issuing shares of our common stock or require us to establish reserves and accrue liabilities with respect to such claims at a future date.  Alternatively, the resolution of certain claims related to contract rejections or other general unsecured claims may result in the dilution of existing stockholders’ interest.  Refer to the Risk Factor entitled “The exercise of all or any number of outstanding Warrants, the issuance of stock-based awards or the issuance of our common stock to settle the claims of general unsecured claimants may dilute your holding of shares of our common stock” for a discussion of the risks involved in the resolution of certain bankruptcy claims.  We also may not have insurance that covers such claims and legal proceedings.  Successful claims or litigation against us for significant amounts could have a material adverse effect on our reputation, business, financial condition, results of operations and cash flows.  Further, even if successful in resolving a claim or legal proceeding, such process could require the attention of members of our senior management, reducing the time they have available to devote to managing our business, and require us to incur substantial legal expenses.

Item 1B.      Unresolved Staff Comments

None.

Item 2.       Properties

Summary of Oil and Gas Properties and Projects

North Dakota & Montana

Our North Dakota & Montana operations primarily include our properties in the Williston Basin targeting the Bakken and Three Forks formations and encompassing approximately 729,700 gross (478,400 net) developed and undeveloped acres as of December 31, 2020.  Our estimated proved reserves in North Dakota & Montana as of December 31, 2020 were 245.8 MMBOE (63% oil), which represented 94% of our total estimated proved reserves and contributed 83.2 MBOE/d of average daily production in the fourth quarter of 2020.

As a result of the sharp decline in commodity prices during 2020 as well as our chapter 11 reorganization, we have significantly decreased our level of capital spending to more closely align with our reduced cash flows from operating activities.  We focused our efforts in this area on maintaining base production with improved artificial lift techniques and targeted workovers and on reducing lease operating expenses.  As of December 31, 2020, we had one completion crew working in the Williston Basin and no active drilling rigs.  In February 2021, we added a drilling rig in this area and we currently plan to add a second rig in October 2021.  We plan to continue with one completion crew in the area for the majority of 2021.

Across our acreage in the Williston Basin, we have implemented custom, right-sized completion designs to increase well performance while reducing cost.  We plan to continue to use right-sized completion designs on wells we drill in 2021. Additionally, we plan to continue to focus on reducing time-on-location and total well cost while maximizing our lateral footage through drilling best practices including utilizing top tier drilling rigs, advanced downhole motor and drill bit technology and our custom drilling fluid system.  

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Colorado

Our Colorado operations primarily include rural properties at our Redtail field in the Denver-Julesburg Basin (“DJ Basin”) targeting the Niobrara and Codell/Fort Hays formations and encompassing approximately 100,600 gross (85,000 net) developed and undeveloped acres as of December 31, 2020.  Our estimated proved reserves in Colorado as of December 31, 2020 were 10.0 MMBOE (59% oil), which represented 4% of our total estimated proved reserves and contributed 8.2 MBOE/d of average daily production in the fourth quarter of 2020.

We have established production in the Niobrara “A”, “B” and “C” zones and the Codell/Fort Hays formations.  During 2020, we primarily focused our efforts on maintaining base production in this area with improved artificial lift techniques and targeted workovers and reducing lease operating expenses.  We completed and turned-in-line two wells in this area in 2020 to test further extents of our acreage.

Reserves

As of December 31, 2020 and 2019, all of our oil and gas reserves were attributable to properties within the United States.  A summary of our proved oil and gas reserves as of December 31, 2020 and 2019 based on average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the respective 12-month periods) is as follows:

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Proved reserves.  Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional development, price changes, engineering and reservoir analysis and other factors.

Total extensions and discoveries of 18.1 MMBOE in 2020 were primarily attributable to successful drilling in the Williston Basin.  New wells drilled in this area as well as the PUD locations added as a result of drilling increased our proved reserves.

Sales of minerals in place totaled 1.3 MMBOE during 2020 and were primarily attributable to the disposition of certain non-operated properties in North Dakota as further described in “Acquisitions and Divestitures” within Item 1 of this Annual Report on Form 10-K.

In 2020, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 206.0 MMBOE.  Included in these revisions were 34.8 MMBOE of proved undeveloped reserves no longer expected to be developed within five years from their initial recognition.  In recent years, we have moved toward a more disciplined capital development program focused on the highest-return projects and the generation of free cash flow.  As a result, price declines such as those we experienced during 2020 result in a change in the timing of our development plans related to PUD reserves in certain areas.  These revisions do not represent the elimination of recoverable hydrocarbons physically in place, as they may be developed in the future.  In addition, there were 120.7 MMBOE of downward adjustments primarily attributable to reservoir and engineering analysis and well performance across our North Dakota, Montana and Colorado assets and 50.5 MMBOE of negative adjustments resulting from lower crude oil, NGL and natural gas prices incorporated into our reserve estimates at December 31, 2020 as compared to December 31, 2019.

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Proved undeveloped reserves.  Our PUD reserves decreased 59% or 74.4 MMBOE on a net basis from December 31, 2019 to December 31, 2020.  The following table provides a reconciliation of our PUDs for the year ended December 31, 2020:

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During 2020, we incurred $64 million in capital expenditures, or $4.49 per BOE, to drill and TIL 14.3 MMBOE of PUD reserves.  These expenditures primarily consisted of completion costs to TIL wells drilled in 2019.  In addition, we added 18.1 MMBOE of PUDs from extensions and discoveries during the year primarily due to successful drilling in the Williston Basin.  We have made an investment decision and adopted a development plan to drill all of our individual PUD locations within five years of the date such PUDs were added.  In that regard, under our current 2021 development plan, we expect to convert approximately 20.6 MMBOE of PUDs to proved developed reserves during the year.

Preparation of reserves estimates.  We maintain adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based.  The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data.  All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance and to validate future development plans.  Current revenue and expense information is obtained from our accounting records, which are subject to our internal controls over financial reporting.  Internal controls over financial reporting are assessed for effectiveness annually using the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  All current financial data such as commodity prices, lease operating expenses, transportation, gathering, compression and other expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete.  Our current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated into the reserve database as well and verified to ensure their accuracy and completeness.  Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, our independent engineering firm Netherland, Sewell & Associates, Inc. (“NSAI”) meets with our technical personnel to review field performance and future development plans.  Following this review, the reserve database and supporting data is furnished to NSAI so that they can prepare their independent reserve estimates and final report.  Access to our reserve database is restricted to specific members of the reservoir engineering department.

The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies.  NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.  

Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Richard B. Talley, Jr. and Mr. Edward C. Roy III.  Mr. Talley, a Licensed Professional Engineer in the State of Texas (No. 102425) and in the State of Louisiana (No. 36998), has been practicing consulting petroleum engineering at NSAI since 2004 and has over 5 years of prior industry experience.  He graduated from University of Oklahoma in 1998 with a Bachelor of Science degree in mechanical engineering and from Tulane University in 2001 with a Master of Business Administration degree.  Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience.  He graduated from Texas Christian University in 1992 with a Bachelor of Science degree in geology and from Texas A&M University in 1998 with a Master of Science degree in geology.  Both technical principals meet or exceed the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.  

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Our Reserves and Reservoir Engineering Manager is responsible for overseeing the preparation of the reserves estimates under the supervision of the Chief Operating Officer, Charles Rimer.  Our Reserves and Reservoir Engineering Manager has more than 10 years of broad reservoir engineering experience in the oil and gas industry, focused across conventional and unconventional evaluation and development projects, including corporate reserves estimations.  He holds a Bachelor of Science degree in petroleum engineering from the Colorado School of Mines and is a member of the Society of Petroleum Engineers.

Acreage

The following table summarizes gross and net developed and undeveloped acreage by core area at December 31, 2020.  Net acreage represents our percentage ownership of gross acreage.  Acreage in which our interest is limited to royalty and overriding royalty interests has been excluded.

Production History

The following table presents historical information about our produced oil and gas volumes.  On September 1, 2020 (the “Emergence Date”), we emerged from chapter 11 bankruptcy.  The application of fresh start accounting resulted in a new basis of accounting and our becoming a new entity for financial reporting purposes.  As a result, the consolidated financial statements after the Emergence Date are not comparable to the consolidated financial statements before that date and the historical financial statements on or before the Emergence Date are not a reliable indicator of our financial condition and results of operations for any period after our adoption of fresh start accounting.  Refer to the “Fresh Start Accounting” footnote in the consolidated financial statements in Item 8 of this Annual Report on Form 10-K for more information.  References to “Successor” refer to our financial position and results of operations after the Emergence Date.  References to “Predecessor” refer to our financial position and results of operations on or before the Emergence Date.  References to “Successor Period” refer to the period from September 1, 2020 through December 31, 2020.  References to “Current Predecessor YTD Period” refer to the period January 1, 2020 through August 31, 2020.  References to “Prior Predecessor YTD Period” refer to the year ended December 31, 2019.  Although GAAP requires that we report on our results for the Successor Period and the Current Predecessor YTD Period separately, in certain circumstances management views our operating results for the year ended December 31, 2020 by combining the results of the applicable Predecessor and Successor periods in order to provide the most meaningful comparison of our current results to prior periods.

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