combined

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, 2021

☐ 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

	WHITING PETROLEUM CORPORATION
	(Exact name of registrant as specified in its charter)

Delaware		20-0098515
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1700 Lincoln Street, Suite 4700 Denver, Colorado		80203-4547
(Address of principal executive offices)		(Zip code)

	(303) 837-1661
	(Registrant’s telephone number, including area code)

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

Common Stock, $0.001 par value		WLL		New York Stock Exchange
(Title of each class)		(Trading Symbol)		(Name of each exchange on which registered)

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.


Large accelerated filer	☒	Smaller reporting company	☐
Accelerated filer	☐	Emerging growth company	☐
Non-accelerated filer	☐

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, 2021: $2,126,000,000.

Number of shares of the registrant’s common stock outstanding at February 17, 2022: 39,240,791 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2022 Annual Meeting of Stockholders are incorporated by reference into Part III.

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“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, future development costs and future abandonment 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.

“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:

The area identified by drilling and limited by fluid contacts, if any, and

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

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

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

The project has been approved for development by all necessary parties and entities, including governmental entities.

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.

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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. Since our inception, we have built a strong asset base through a combination of property acquisitions, development of proved reserves and exploration activities. We are currently focusing our capital programs on drilling and workover opportunities that we believe provide attractive well-level returns in order to maintain consistent production levels and generate free cash flow. In addition, we are selectively pursuing acquisitions that complement our existing core properties. During 2021, we focused on high-return projects in our asset portfolio that generated significant cash flow from operations. 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. Refer to “Acquisitions and Divestitures” below for a summary of certain recent asset purchase and sale activity.

As of December 31, 2021, our estimated proved reserves totaled 326.0 MMBOE and our 2021 average daily production was 91.9 MBOE/d.

The following table summarizes, by core area, our estimated proved reserves as of December 31, 2021 with the corresponding pre-tax PV10% values, our fourth quarter 2021 average daily production rates, and our total standardized measure of discounted future net cash flows as of December 31, 2021:

Proved Reserves ⁽¹⁾

Pre-Tax

4^th Quarter 2021

Natural

PV10%

Average Daily

Oil

NGLs

Gas

Total

Value ⁽²⁾

Production

Core Area

(MMBbl)

(Bcf)

(MMBOE)

Oil

(in millions)

(MBOE/d)

North Dakota & Montana

183.6

66.3

422.5

320.3

57%

4,342

91.6

Other ⁽³⁾

5.0

0.1

3.5

5.7

88%

1.2

Total

188.6

66.4

426.0

326.0

58%

4,381

92.8

Discounted future income tax expense

(702)

Standardized measure of discounted future net cash flows

3,679

(1)

Oil and gas reserve quantities and related discounted future net cash flows have been derived from a WTI oil price of $66.56 per Bbl and a Henry Hub gas price of $3.60 per MMBtu, which were calculated using an average of the first-day-of-the-month price for each month within the 12 months ended December 31, 2021 as required by SEC and FASB guidelines.

(2)

Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows (the “Standardized Measure”), which is the most directly comparable GAAP financial measure. Pre-tax PV10% is computed on the same basis as the Standardized Measure but without deducting future income taxes. We believe pre-tax PV10% is a useful measure for investors when evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our pre-tax PV10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, pre-tax PV10% is not a substitute for the Standardized Measure. Our pre-tax PV10% and Standardized Measure do not purport to present the fair value of our proved oil, NGL and natural gas reserves.

(3)	Primarily includes non-core oil and gas properties located in Arkansas, Colorado, Mississippi, New Mexico, Texas and Wyoming.

During 2021, we incurred $247 million in exploration and development (“E&D”) expenditures for the drilling of 41 gross (25.5 net) wells and the completion of 57 gross (34.4 net) operated and nonoperated wells.

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Our current 2022 E&D budget is a range of $360 million to $400 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 and could adjust our E&D budget, our cash on hand or our borrowings outstanding under our credit facility.

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.

Acquisitions and Divestitures

Recent Acquisitions and Divestitures. In September 2021, we completed the acquisition of interests in oil and gas properties located in Mountrail County, North Dakota for an aggregate purchase price of $271 million (before closing adjustments).

In December 2021, we completed the acquisition of additional interests in oil and gas properties located in Mountrail County, North Dakota for an aggregate purchase price of $32 million (before closing adjustments).

Subsequent to December 31, 2021, we entered into a purchase and sale agreement to acquire additional interests in oil and gas properties located in Mountrail County, North Dakota for an aggregate purchase price of $240 million (before closing adjustments). We expect this transaction to close in March 2022. We intend to finance this acquisition with cash on hand and borrowings under our Credit Agreement.

On a combined basis, our recent Williston Basin acquisitions included interests in 76 new gross producing oil and gas wells and increased interests in 527 existing gross producing wells. Overall, the acquisitions effectively added 136.2 net producing wells and included approximately 23,300 net undeveloped acres.

In September 2021, we completed the divestiture of all of our interests in producing assets and undeveloped acreage, including the associated midstream assets, of our Redtail field located in the Denver-Julesburg Basin of Weld County, Colorado for aggregate sales proceeds of $171 million (before closing adjustments). The production from the divested properties (which was approximately 51% oil) represented approximately 8% of our average total production as of the divestiture date.

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).

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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.

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. Our assets, dedicated professionals, commitment to environmental stewardship and value-focused business execution position Whiting for success. 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 731,100 gross (479,700 net) developed and undeveloped acres in this area. After suspending all drilling and completion activity in 2020 in response to depressed crude oil prices, in February 2021 we commenced drilling with one rig in the Williston Basin and added a second rig at the end of September 2021. We had one active completion crew for three quarters of 2021, and we brought online 56 gross (36.8 net) operated Bakken and Three Forks wells in the Williston Basin during the year. Under our current 2022 capital program, we expect to execute a two-rig drilling program for the majority of the year along with a slight increase in completion activity. We plan to TIL approximately 68 gross (44.4 net) wells in this area during the year.

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. During 2021, we were focused on high-return projects in our asset portfolio that generated significant cash flow from operations. We are currently focusing our capital programs on drilling and workover opportunities that we believe provide the greatest well-level returns in order to maintain consistent production levels and generate free cash flow, while selectively pursuing acquisitions that complement our existing core properties. 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, in each of the last three years we sold certain oil and gas properties that could no longer compete for capital or that otherwise 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 two-way collars and swaps to provide an attractive base commodity price level.

Commitment to Safety and Social Responsibility. We are committed to developing the energy resources the world needs in a safe and responsible way that allows us to protect our employees, our contractors, our vendors, the public and the environment while also meeting or exceeding regulatory requirements. We continually evolve our practices to better protect wildlife habitats and communities, to reduce freshwater use in our development process, to identify and reduce methane emissions from our operations, to encourage waste reduction programs and to promote worker safety. Additionally, we are committed to transparency in reporting our environmental, social and governance performance and to monitoring such performance through various measures, some of which are tied to our short-term incentive program for all employees. Refer to 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 2014, we have completed 7 separate significant acquisitions of producing and undeveloped properties for total estimated proved reserves of 238.7 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.

Return of Capital. As a result of our strong operating base and our disciplined financial approach, we reduced the borrowings under our Credit Agreement to zero as of December 31, 2021. We expect that our business strategy will continue to provide sizable cash flow generation which will enable us to return capital to our shareholders and continue to pursue acquisitions that add to our inventory, while maintaining a strong balance sheet. As a first step in delivering on this commitment, in February 2022 we announced an initial regular dividend payment which will begin in the first quarter of 2022. Our Board and management are committed to returning capital in line with our industry peers and we will continue to evaluate all forms of capital returns, including buying back outstanding shares and paying variable dividends.

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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, 2021, we had interests in 4,720 gross (1,917 net) productive wells on approximately 844,700 gross (539,900 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 26 years of experience in the oil and gas industry. Our personnel have extensive experience in our core geographical areas, all 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 our oil and gas reservoirs. We leverage many technologies in support of data gathering, information analysis and production optimization. Artificial intelligence and machine learning solutions support both field and corporate business processes. Data management and reporting practices improve the availability, accuracy and analysis of our information in a cycle of continuous improvement. Emerging technologies are evaluated on a regular basis, ensuring we are implementing the best technologies for our business needs.

We continue to advance the development of our completion techniques to match the varying reservoir properties across the Williston Basin while utilizing the latest completion technologies available. Each new well provides us with valuable data that is evaluated and used in conjunction with publicly available third-party data to adjust the overall completion design for each of our prospect areas and unlock maximum value from our assets. Our 2022 program will continue to focus on reducing time-on-location through efficiency gains in our drilling practices and completion techniques.

Commitment to Cost Management. We are committed to continued cost management strategies to remain a lower-cost operator. During 2020, in response to the sharp decline in commodity prices, as well as our chapter 11 reorganization, we significantly reduced our operating and overhead costs. During 2021, we continued to create lease operating expense efficiencies across the majority of our properties while maintaining our substantial production base. These cost efficiencies and production maintenance efforts resulted in reductions in saltwater disposal costs by 25%, utility costs by 10% and lost oil volumes to downtime by 20% from 2020 to 2021.

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, 2021 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.


						Estimated
						Future Capital
	Oil	NGLs	Natural Gas	Total	% of Total	Expenditures ⁽¹⁾
	(MMBbl)	(MMBbl)	(Bcf)	(MMBOE)	Proved	(in millions)
North Dakota & Montana
PDP	138.5	53.5	338.6	248.5	78%
PDNP	4.8	1.4	9.8	7.8	2%
PUD	40.3	11.4	74.1	64.0	20%
Total proved	183.6	66.3	422.5	320.3	100%	$	572.2
Other ⁽²⁾
PDP	4.6	0.1	2.9	5.2	91%
PDNP	0.4	-	0.6	0.5	9%
Total proved	5.0	0.1	3.5	5.7	100%	$	8.5
Total Company
PDP	143.1	53.6	341.5	253.7	78%
PDNP	5.2	1.4	10.4	8.3	2%
PUD	40.3	11.4	74.1	64.0	20%
Total proved	188.6	66.4	426.0	326.0	100%	$	580.7

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(1)	Estimated future capital expenditures incorporate numerous assumptions and are subject to many uncertainties, including oil and natural gas prices, costs of oil field goods and services, drilling results, well abandonment costs and several other factors.

(2)	Primarily includes non-core oil and gas properties located in Arkansas, Colorado, Mississippi, New Mexico, Texas and Wyoming.

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

There is a high degree of competition in the oil and gas industry 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, better sustain production in periods of low commodity prices and evaluate, bid for and purchase a greater number of properties and prospects than our resources permit. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation or regulation enacted by state, local and U.S. government bodies and their associated agencies, especially with regard to environmental protection and climate-related policies. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or the resultant effects on our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and our larger competitors may be able to better absorb the burden of such legislation and regulation, which would also adversely affect our competitive position. Refer to “Government Regulation” below as well as Item 1A within this Annual Report on Form 10-K for more information on and the potential associated risks resulting from existing and future legislation and regulation of our industry. Additionally, 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 revenues.

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 depends on a number of factors, including an available qualified talent pool, compensation plans, benefits programs, talent development efforts, career opportunity generation and our work environment. As of January 31, 2022, we had approximately 356 full-time employees, 197 of which were field employees, primarily located in North Dakota and Montana, and 159 of which were corporate employees, primarily located in Colorado. None of our employees are represented by any labor unions. We also engage independent contractors and consultants to support our work in specific areas.

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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 employees and contractors to identify and report potential hazards, assess risks inherent to our industry and stop work when necessary. Through health and safety training, we prepare our employees and contractors to use industry best practices and standards to mitigate risk in a manner that protects themselves, their co-workers, the public and property. We have developed a comprehensive safety management system that includes recurring risk assessment, hazard recognition and mitigation and emergency response preparedness training, protective measures including adequate personal protective equipment, life-saving rules, onboarding processes, contractor safety management, partner surveys, comprehensive audits, quarterly safety summits, executive-level reviews of incidents and ad-hoc safety stand-downs. In 2021, Whiting established corporate goals specifically related to employee and contractor safety. All employee and executive short-term incentive compensation is impacted by our performance relative to these safety goals and other performance metrics deemed material by the Board. We monitor employee and contractor safety performance based on several metrics, which are communicated to employees through a dashboard that is updated continuously. These metrics are also communicated regularly to senior management and key operational employees to monitor progress, provide opportunities for training and reinforce the importance of safety. Two key metrics that we monitor are our Combined Total Recordable Incident Rate and our Days Away, Restricted and/or Transferred Rate. Whiting seeks to only partner with contractors and vendors who share our commitment to safety.

Diversity, Equity and Inclusion. We recognize the advantages of a company culture that embraces diversity, constructive debate and differing viewpoints, continuous learning, servant leadership and an engaged workforce. 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 under federal, state or local law. Whiting’s leadership is mindful of ways to increase the diversity of our workforce and our Board. In order to continually grow our diversity of background and experience, we actively make appropriate efforts to increase the percentage of our workforce that is female or minority while also maintaining the high qualification standards required of Whiting employees. Additionally, we have achieved gender parity among our independent directors.

Ethics. Whiting is committed to demonstrating adherence to our corporate core values, the first of which is “Highest Integrity.” We expect all of our employees, officers and directors to adhere to our Code of Business Conduct and Ethics. Whiting has an Ethics Hotline for the purpose of allowing all employees an avenue for confidential, anonymous submission of concerns.

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, market-competitive health benefits and other appropriate benefits including workplace flexibility.

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 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 envision a successful and fulfilling career progression within our company.

Refer to our Sustainability Report published on our website for performance highlights regarding various human capital measures 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.

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

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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”) and Office of Natural Resources Revenue (the “ONRR”) establish 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, the ONRR 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 the 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.

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, 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, 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

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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 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 June 2016, the Protecting our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act became law. The PIPES Act strengthens PHMSA’s safety authority, including by expanding 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.

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 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

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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 noncompliance. We have incurred in the past, and expect to incur in the future, capital expenditures and operating 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 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:

●	to investigate the source and extent of impacts from released hazardous substances;

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●	to remove or remediate previously disposed materials, including materials disposed or released by prior owners or operators or other third parties;

●	to clean up and remediate contaminated property, including both soils and contaminated groundwater;

●	to perform remedial operations to prevent future contamination, including the plugging and abandonment of wells drilled and left inactive by prior owners and operators; or

●	to pay some or all of the costs of any such action.

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, and 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, or that the EPA could implement broader RCRA reforms 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 and 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 (the “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, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

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

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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 water bodies (including wetlands) that have a “significant nexus” to navigable waters of the United States. The rule, however, was vacated by two separate federal district courts in late 2021. On December 7, 2021, the EPA and the Army Corps of Engineers published in the Federal Register a proposed rule that would largely reinstate the previous 1986 “waters of the United States” rule and guidance with certain amendments to reflect “consideration of the agencies’ statutory authority under the CWA and relevant Supreme Court decisions” (the “2021 Proposed Rule”). Publication of the 2021 Proposed Rule in the Federal Register triggered a 60-day public comment period, sometime after which the rule is expected to be finalized by the agencies. Although the outcome of the 2021 Proposed Rule and any additional amendments to the regulations is unknown, the regulations under the Biden administration are undoubtedly more stringent in terms of scope. 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 June 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. In August 2020, the EPA enacted an amendment to the Subpart OOOOa Rule, which removed all methane-specific requirements from production and processing segments and removed volatile organic compounds and methane emission standards from transmission and storage facilities. On June 30, 2021, however, President Biden signed into law a joint Congressional resolution disapproving and invalidating much of the 2020 rule amendments under the prior administration, including the 2020 rule’s rescission of the methane requirements. On November 15, 2021, the EPA published in the Federal Register a proposed rule that would update and expand existing requirements for the oil and gas industry, as well as create significant new requirements and standards for new, modified and existing oil and gas facilities. The proposed new requirements would include, for example, new standards and emission limitations applicable to storage vessels, well liquids unloading, pneumatic controllers and flaring of natural gas at both new and existing facilities. The proposed rules for new and modified facilities are estimated to be finalized by the end of 2022, while any standards finalized for existing facilities will require further state rulemaking actions over the next several years before they become applicable and effective.

Certain states have also adopted, or are considering, regulations addressing methane releases 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.

Environmental Protection and Natural Gas Flaring. North Dakota law restricts the flaring of natural gas from wells that have not been connected to a gas gathering line for a period of one year from the date of the well’s first production. After one year, an operator is required to cap the well, connect it to a gas gathering line, find acceptable alternative uses for a percentage of the flared gas or apply to the North Dakota Industrial Commission (the "NDIC") for a written exemption for any future flaring.

In addition, NDIC rules for new drilling permits require the submission of gas capture plans setting forth the operator’s plan to capture and not flare produced gas, regardless of whether it has been or will be connected within the first year of production. The NDIC currently requires us to capture 91% of the natural gas produced from a field, with various allowances for, including but not limited to, initial production testing, force majeure events and temporary midstream outages. If an operator is unable to attain the applicable gas capture percentage goal at maximum efficient rate, wells will be restricted in production to 200 barrels of crude oil per day if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or otherwise crude oil production from such wells is not permitted to exceed 100 barrels of crude oil per day. However, the NDIC will consider temporary exemptions from the foregoing restrictions or for other types of extenuating circumstances after notice and hearing if the effect is a significant net increase in gas capture within one year of the date such relief is granted. Monetary penalty provisions also apply under this regulation if an operator fails to timely file for a hearing with the NDIC upon being unable to meet such percentage goals or if the operator fails to timely implement

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production restrictions once below the applicable percentage goals. Ongoing compliance with the NDIC’s flaring requirements or the imposition of any additional limitations on flaring could result in increased costs and have an adverse effect on our operations. However, it is expected that any such change would not disparately affect us and our competitors. We believe we operated in compliance with the NDIC standards throughout 2021.

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. No assurance can be given as to whether or not more stringent hydraulic fracturing 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.

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

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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 few 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. In November 2021, the U.S. House of Representatives passed the H.R. 5376 bill, which would amend the CAA to impose a fee of $1,500 per ton of methane emitted above specified thresholds from onshore petroleum and natural gas production facilities, natural gas processing facilities, natural gas transmission and compression facilities, and onshore petroleum and natural gas gathering and boosting facilities, among other facilities. The U.S. Senate is currently considering H.R. 5376 and may adopt, modify, or eliminate the methane fee. 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 such effects occur, they could have a material adverse effect on our assets and limit the type, timing and location of our 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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Additionally, the prices that we receive for our oil and natural gas production generally reflect a discount, but sometimes a premium, to 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.

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 or its related variants, 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, can and has led to increased volatility in oil and natural gas prices. Finally, 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 locations for a period of time. The occurrence or continuation of any of these events could lead to decreased revenues and limit our ability to execute our business plan, which 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 prices.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions or inaction of 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 and increases, in an effort to achieve certain global supply or demand targets or to achieve certain crude oil price outcomes. 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, and they may take actions that have the effect of reducing oil prices. 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.

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 (“Army Corps”) had violated the National Environmental Policy Act when it granted an easement relating to a portion of the Dakota Access Pipeline (“DAPL”) because it had failed to prepare an environmental impact statement (“EIS”). 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. After issuing a stay of the order to shut down the pipeline on August 5, 2020, the U.S. Court of Appeals for the D.C. Circuit (“D.C. Appellate Court”), on January 26, 2021, 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 Army Corps develops an EIS. On May 21, 2021, the D.C. District Court ruled that it would not issue an injunction requiring a shutdown of the DAPL and that the DAPL could continue to operate while the Army Corps prepares an EIS. The D.C. District Court further ruled on June 22, 2021 that the litigation be dismissed and that the plaintiffs could renew their challenge to DAPL upon the Army Corps’ issuance of an EIS. Barring different discretionary action by the Army Corps, these rulings allow the DAPL’s continued operation unless and until new challenges are made and succeed following issuance of the EIS, which the Army Corps anticipates issuing in the fall of 2022. On September 20, 2021, the DAPL’s owner filed a petition with the U.S. Supreme Court seeking review of the lower courts’ decisions requiring a new EIS and permit, and the plaintiff tribes and Army Corps filed briefs opposing such review. However, the U.S. Supreme Court declined to accept the case for review. The potential disruption of transportation as a result of the DAPL being shut down or the anticipation of the 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.

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Substantially all 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.

Substantially all of our producing properties are geographically concentrated in the Williston Basin of North Dakota and Montana. At December 31, 2021, approximately 98% 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 risk of delays or interruptions of production from wells on these properties caused by transportation capacity constraints, curtailment of production or the unavailability of transportation infrastructure for the 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 interruptions in transportation of our production. 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.

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 and may subject us to substantial liability claims.

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 and may subject us to liability. 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 us to find alternative means to transport oil, NGL and natural gas production. Such alternative means may not be available or 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.

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. We could be subject to fines, penalties or other damages associated with any event of this nature.

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

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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:

●	environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

●	abnormally pressured formations;

●	mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

●	the loss of well control;

●	fires and explosions;

●	personal injuries and death;

●	terrorist attacks; and

●	natural disasters.

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.

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 or economic trends in the broader economy, 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, and any resulting price increases, could delay or adversely affect our exploration and development operations, which could restrict such operations or have a material adverse effect on our business, financial condition, results of operations or cash flows.

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 due to severe weather. 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 and reduce our cash flows. Severe weather events may increase in duration and intensity as a result of climate change, in which case these risks will be greater in the future.

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

We operate 88% of our net productive oil and natural gas wells, which represents 92% of our proved developed producing reserves as of December 31, 2021. 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.

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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, banking information 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 and 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 or loss of data from cybersecurity attacks, computer viruses or malware, or that third-party service providers could cause a breach of our data. 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.

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:

●

unauthorized disclosure of sensitive or personally identifiable information, including by cyber-attacks or other security breaches, could cause loss of data, give rise to remediation or other expenses, expose us to liability under federal and state laws, reduce our customers’ willingness to do business with us, disrupt the services we provide to customers and property owners and subject us to litigation and investigations;

●	a cyber-attack on a third party could result in supply chain disruptions which could delay or halt development of additional infrastructure, effectively delaying the start of cash flow from the project;

●	a cyber-attack on downstream or midstream pipelines could prevent us from delivering product, resulting in a loss of revenues;

●	a cyber-attack on a communications network or power grid could cause operational disruption resulting in a loss of revenues;

●	a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and

●	business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common shares.

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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 or that production will fall short of our estimates. 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 or, even if economical, less successful than we projected. Further, many factors may curtail, delay or cancel drilling, including, but not limited to, the following:

●	substantial or extended declines in oil, NGL and natural gas prices;

●	delays imposed by or resulting from compliance with regulatory requirements;

●	delays in or limits on the issuance of drilling permits by state agencies or on our federal leases, including as a result of government shutdowns;

●	pressure or irregularities in geological formations;

●	limitations in infrastructure, including pipeline takeaway and refining and processing capacity;

●	shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services;

●	equipment failures, accidents, fires and explosions, including ruptures of pipelines or storage facilities or train derailments;

●	adverse weather events, such as floods, blizzards, ice storms, tornadoes and freezing temperatures; and

●	title defects.

Unless we replace our oil and natural gas reserves, our reserves and production will decline and 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.

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 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.

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Our assessment of a potential acquisition 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.

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 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 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 strategic transaction 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 achieve our strategic goals.

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. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation or regulation enacted by state, local and U.S. government bodies and their associated agencies, especially with regards to environmental protection and climate-related policies. Such laws and regulations may substantially increase the costs of exploring for or developing or producing oil and natural gas and our larger competitors may be able to better absorb the burden of such legislation and regulation, which would also adversely affect our competitive position. 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, such as wind, solar, nuclear, hydrogen 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. These alternative energy sources may increase in the future in response to concerns about climate change or the enactment of climate-related policies. Decreased demand for our products could adversely affect our business, financial condition, results of operations or cash flows.

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Risks Related to Our Capital Structure and Financial Results

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

We enter into hedging transactions relating to our oil, natural gas and NGL production to reduce our exposure to fluctuations in the price of oil, natural gas and NGLs. Our hedging transactions to date have consisted of financially settled crude oil, natural gas and NGL options contracts, primarily two-way collars and swaps, placed with major financial institutions. As of February 17, 2022, we had crude oil derivative contracts (consisting of collars and swaps) covering the sale of 39,000 Bbl and 16,000 Bbl of oil per day for the remainder of 2022 and the first three quarters of 2023, respectively. Additionally, we had natural gas derivative contracts (consisting of collars, swaps and basis swaps) covering the sale of 95,000 MMBtu and 61,000 MMBtu of natural gas per day through the remainder of 2022 and first three quarters of 2023, respectively. Finally, we had NGL derivative contracts (consisting of swaps) covering the sale of 223,000 gallons of NGLs per day for the remainder of 2022. 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, natural gas and NGLs, 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, natural gas and NGLs. Furthermore, if we are party to hedging transactions that cover a smaller percentage of our production than our competitors, we may be more adversely affected by declines in oil and natural gas prices than those competitors. Additionally, hedging transactions may expose us to cash margin requirements.

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. Additionally, settlements paid on hedging arrangements may significantly decrease our cash flow from operating activities in periods where current commodity prices are higher than the ceilings or swap price of certain hedging arrangements.

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. 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.

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:

●	historical production from the area compared with production rates from other producing areas;

●	the assumed effect of governmental regulation; and

●	assumptions about future prices of oil, NGLs and natural gas including differentials, production and development costs, gathering and transportation costs, severance and excise taxes, capital expenditures and availability of funds.

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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, 2021 were $66.56 per Bbl of oil and $3.60 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 were $1.00 per Bbl lower, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2021 would have decreased by $71 million. If the 12-month average natural gas prices used to calculate our natural gas reserves were $0.10 per MMBtu lower, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2021 would have decreased by $17 million.

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

As of December 31, 2021, we had U.S. federal NOLs of $3.3 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.

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

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

●	prepay, redeem or repurchase certain debt;

●	pay dividends or make other distributions or repurchase or redeem our capital stock;

●	make loans and investments;

●	incur or guarantee additional indebtedness or issue preferred stock;

●	create certain liens;

●	enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

●	sell assets;

●	consolidate, merge or transfer all or substantially all of our assets and those of our restricted subsidiaries taken as a whole;

●	engage in transactions with affiliates;

●	enter into hedging contracts; and

●	create unrestricted subsidiaries.

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The Credit Agreement requires us, as of the last day of any quarter, to maintain commodity hedges covering a minimum of 50% of our projected production for the succeeding twelve months. If our consolidated net leverage ratio equals or exceeds 1.0 to 1.0 as of the last day of any fiscal quarter we will also be required to hedge 35% of our projected production for the next succeeding twelve months. We are also limited to hedging a maximum of 85% of our production from proved reserves. In addition, the Credit Agreement requires us, as of the last day of any quarter to maintain the following ratios (as defined in the 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 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 in the Credit Agreement is redetermined on April 1 and October 1 of each year and may be the subject of special redeterminations described in the 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 Credit Agreement and we may not have, or be able to obtain, the funds necessary to do so.

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

As of December 31, 2021, we had no borrowings and $1 million in letters of credit outstanding under the Credit Agreement with $749 million of available borrowing capacity. The Credit Agreement matures on April 1, 2024. We are allowed to incur additional indebtedness, provided that we meet certain requirements in the 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:

●	requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

●	limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;

●	increasing the possibility that we may be unable to generate sufficient cash to pay, when due, the principal of, interest on or other amounts due or otherwise refinance our indebtedness;

●	limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

●	placing us at a competitive disadvantage relative to other less leveraged competitors;

●	making us vulnerable to increases in interest rates, because debt under the Credit Agreement is subject to certain rate variability;

●	making us more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially declines in oil and natural gas prices; and

●	reducing our borrowing base when oil and natural gas prices decline and our ability to maintain compliance with our financial covenants becomes more difficult, which may reduce or eliminate our ability to fund our operations.

Should we have borrowings outstanding under the Credit Agreement in the future, 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 any outstanding debt. Refer to the Risk Factor entitled “The Credit Agreement contains various covenants limiting the discretion of our management in operating our business.”

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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 from operations, cash on hand and borrowings under the Credit Agreement, although we may seek capital from additional sources as needed. Our cash flow from operations and access to capital is subject to a number of variables, including, but not limited to:

●	the prices at which oil and natural gas are sold;

●	our proved reserves;

●	the level of oil and natural gas we are able to produce from existing wells;

●	the costs of producing oil and natural gas; and

●	our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under the 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 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 any indebtedness we incur 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 commitments, including any indebtedness that we may incur in the future under the Credit Agreement or other arrangements. 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 meet our obligations. Factors that may cause us to generate cash flow that is insufficient to meet our obligations include 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 any debt. If we do not generate sufficient cash flow from operations to service any indebtedness we incur, we may be required to undertake various alternative financing plans, which may include:

●	refinancing or restructuring all or a portion of our debt;

●	seeking alternative financing or additional capital investment;

●	selling strategic assets;

●	reducing or delaying capital investments; or

●	revising or delaying our strategic plans.

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 incur indebtedness in the future and cannot make scheduled payments on that 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 Credit Agreement could declare all outstanding principal and interest to be due and payable. Additionally, the lenders under the Credit Agreement could terminate their commitments to loan money and could foreclose against our assets collateralizing our

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These laws and regulations can also increase our costs and limit our business activities. For example, 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; and limit or prohibit drilling or well completion activities on certain lands. We incur significant costs in our efforts to comply with applicable laws and regulations.

The regulatory environment in which we operate changes frequently, often through the imposition of new or more stringent environmental and other requirements, some of which may apply retroactively. We cannot predict the nature, timing, cost or effect of such additional requirements, but they may have a variety of adverse effects on us. Refer to “Business—Government Regulation” in Item 1 of this Annual Report on Form 10-K for a discussion of some potential regulatory changes that could affect our business.

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

Continuing and increasing political, social and scientific attention to the issue of climate change has resulted in legislative, regulatory and other initiatives, including international agreements, to reduce greenhouse gas (“GHG”) emissions such as carbon dioxide and methane. Policy makers and regulators at the federal and state levels have already imposed, or stated intentions to impose, laws and regulations designed to quantify and limit the emissions of GHG. Refer to “Business—Government Regulation—Global Warming and Climate Change” in Item 1 of this Annual Report on Form 10-K for a discussion of certain existing and proposed laws and regulations intended to address climate change issues. Existing and future laws and regulations relating to climate change and GHG emissions could increase our costs, reduce demand for our products, limit our growth opportunities, impair our ability to develop our reserves and have other adverse effects on our business.

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.

In addition, 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 such effects occur, they could have a material adverse effect on our business, financial condition, results of operations and cash flows, and could also limit the type, timing and location of our operations.

Finally, increased demand for low-carbon or renewable energy sources from consumers could reduce the demand for, and the price of, the products we produce. Technological changes, such as developments in renewable energy and low-carbon transportation, could also adversely affect demand for our products.

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, natural gas flaring, 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.

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 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.

A negative shift in investor sentiment regarding 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. Historic 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 adopted policies to divest holdings in the oil and gas sector based on 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.

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 acquisitions or development projects, impacting our future financial results.

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

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 resolved unfavorably to us. In addition, the claims resolutions process in connection with our previous filing for and emergence from the voluntary cases under chapter 11 of the Bankruptcy Code (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 may be satisfied through the issuance of shares of our common stock or other remedy or agreement under and pursuant to the Plan. As discussed in more detail in the “Commitments and Contingencies” footnote in the notes to the consolidated financial statements in Item 8 of this Annual Report on Form 10-K under the heading “Chapter 11 Cases,” it is possible with respect to certain claims that we could be required or may have the option to make cash payments to resolve claims instead of issuing shares of our common stock or 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 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 we are successful in resolving a claim or legal proceeding, the process will require the attention of members of our senior management, reducing the time they have available to devote to managing our business, and may require us to incur substantial legal expenses.

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Reserves

As of December 31, 2021 and 2020, 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, 2021 and 2020 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:


	Oil	NGLs	Natural Gas	Total
	(MBbl)	(MBbl)	(MMcf)	(MBOE)
2021
Proved developed reserves	148,317	55,006	351,914	261,975
Proved undeveloped reserves	40,287	11,359	74,135	64,002
Total proved reserves	188,604	66,365	426,049	325,977
2020
Proved developed reserves	128,227	37,961	251,316	208,074
Proved undeveloped reserves	35,042	8,406	52,301	52,165
Total proved reserves	163,269	46,367	303,617	260,239

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 20.3 MMBOE in 2021 were primarily attributable to successful drilling in the Williston Basin. New wells drilled in this area, as well as the proved undeveloped (“PUD”) locations added as a result of offsetting drilling, increased our proved reserves.

Purchases of minerals in place totaled 15.9 MMBOE during 2021 and were primarily attributable to two acquisitions in the Williston Basin, as further described in “Acquisitions and Divestitures” within Item 1 of this Annual Report on Form 10-K.

Sales of minerals in place totaled 10.7 MMBOE during 2021 and were primarily attributable to the disposition of all of our interests in the producing assets and undeveloped acreage of our Redtail field located in the Denver-Julesburg Basin of Weld County, Colorado, as further described in “Acquisitions and Divestitures” within Item 1 of this Annual Report on Form 10-K.

In 2021, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 73.8 MMBOE. Included in these revisions were (i) 70.1 MMBOE of upward adjustments resulting from higher crude oil, NGL and natural gas prices incorporated into our reserve estimates at December 31, 2021 as compared to December 31, 2020, (ii) 12.8 MMBOE of upward adjustments primarily attributable to reservoir and engineering analysis and well performance across our North Dakota and Montana assets, and (iii) 0.8 MMBOE of upward adjustments attributable to narrower differentials and stronger NGL yields. The above upward adjustments were partially offset by 9.9 MMBOE of downward adjustments due to increased operating expenses.

Proved undeveloped reserves. Our PUD reserves increased 23% or 11.8 MMBOE on a net basis from December 31, 2020 to December 31, 2021. The following table provides a reconciliation of our PUD reserves for the year ended December 31, 2021:


		Total
		(MBOE)
PUD balance—December 31, 2020		52,165
Converted to proved developed through drilling		(20,354)
Added from extensions and discoveries		18,709
Purchased		4,405
Revisions		9,077
PUD balance—December 31, 2021		64,002

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Material changes in proved undeveloped reserves for the year ended December 31, 2021 included the following:

●

Converted to proved developed through drilling. During 2021, we incurred $100 million in capital expenditures, or $4.94 per BOE, to drill and TIL 20.4 MMBOE of PUD reserves. These expenditures primarily consisted of completion costs to TIL wells we drilled in 2019 and 2020.

●

Added from extensions and discoveries. We added 18.7 MMBOE of PUDs from extensions and discoveries during the year primarily due to successful drilling in the Williston Basin.

●

Purchased. During 2021 we added total PUD volumes of 4.4 MMBOE primarily through two acquisitions in the Williston Basin, as further described in “Acquisitions and Divestitures” in Item 1 of this Annual Report on Form 10-K.

●

Revisions. In 2021, revisions to previous estimates increased proved undeveloped reserves by a net amount of 9.1 MMBOE. Included in these revisions were (i) 7.2 MMBOE of upward adjustments from higher crude oil, NGL and natural gas prices incorporated into our estimates at December 31, 2021 as compared to December 31, 2020 and (ii) 1.9 MMBOE of upward adjustments attributable to well performance across our assets in North Dakota and Montana.

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. Under our current 2022 development plan, we expect to convert approximately 24.6 MMBOE (or 38%) of our PUDs to proved developed reserves during the year.

Preparation of reserves estimates. We believe that 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, abandonment costs 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 as a petroleum engineering consultant 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 as a petroleum geoscience consultant 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 11 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, 2021. 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.


	Developed Acreage		Undeveloped Acreage ⁽¹⁾		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
North Dakota & Montana	710,466	464,129	20,601	15,538	731,067	479,667
Other⁽²⁾	88,433	53,988	25,151	6,247	113,584	60,235
	798,899	518,117	45,752	21,785	844,651	539,902

(1)

Out of a total of approximately 45,800 gross (21,800 net) undeveloped acres as of December 31, 2021, the portion of our net undeveloped acreage that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 58% in 2022, 6% in 2023 and 5% in 2024. We have not assigned any proved undeveloped reserves to locations scheduled to be drilled after lease expiration.

(2)	Other includes Arkansas, Colorado, Louisiana, Michigan, Mississippi, New Mexico, Oklahoma, Texas, Utah and Wyoming.

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 “2020 Successor Period” refer to the period from September 1, 2020 through December 31, 2020. References to “2020 Predecessor Period” refer to the period January 1, 2020 through August 31, 2020. Although GAAP requires that we report on our results for the 2020 Successor Period and the 2020 Predecessor Period separately, in certain circumstances management views our 2020 operating results by combining the results of the applicable Predecessor and Successor periods in order to provide the most meaningful comparisons to current and prior periods.

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	Successor				Predecessor		Non-GAAP		Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020		Combined Year Ended December 31, 2020		Year Ended December 31, 2019
Total company production
Oil (MMBbl)		19.3		6.8		15.3		22.1		29.8
NGL (MMBbl)		7.2		2.1		4.5		6.6		7.6
Natural gas (Bcf)		42.0		14.3		29.7		44.0		50.5
Total (MMBOE)		33.5		11.4		24.7		36.1		45.8
Daily average (MBOE/d)		91.9		93.0		101.4		98.6		125.5
Sanish field production ⁽¹⁾
Oil (MMBbl)		5.8		1.9		4.2		6.1		5.8
NGL (MMBbl)		1.2		0.4		0.8		1.2		1.1
Natural gas (Bcf)		8.6		2.8		5.5		8.3		7.6
Total (MMBOE)		8.4		2.8		5.9		8.7		8.2
Average sales prices (before the effects of hedging)
Oil (per Bbl)	$	64.77	$	37.05	$	28.86	$	31.40	$	50.06
NGLs (per Bbl)	$	22.53	$	5.90	$	4.45	$	4.91	$	6.76
Natural gas (per Mcf)	$	2.34	$	0.48	$	(0.06)	$	0.11	$	0.57
Average production costs (per BOE)
Lease operating expenses	$	7.23	$	6.52	$	6.40	$	6.43	$	7.17
Transportation, gathering, compression and other	$	0.90	$	0.71	$	0.90	$	0.84	$	0.93

(1)	The Sanish field was our only field that contained 15% or more of our total proved reserve volumes at the end of the years presented.

Productive Wells

The following table summarizes gross and net productive oil and natural gas wells by core area at December 31, 2021. A net well represents our percentage ownership of a gross well. Wells in which our interest is limited to royalty and overriding royalty interests are excluded.


	Oil Wells		Natural Gas Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
North Dakota & Montana	3,394	1,527	-	-	3,394	1,527
Other ⁽¹⁾	1,256	350	70	40	1,326	390
Total	4,650	1,877	70	40	4,720	1,917

(1)	Other primarily includes non-core oil and gas properties located in Colorado, New Mexico, Texas and Wyoming.

Oil and Gas Drilling Activity

We are engaged in drilling activities on properties presently owned, and we intend to drill or develop other properties acquired in the future. The following table sets forth our wells completed for the last three years. A dry well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. A productive well is an exploratory, development or extension well that is not a dry well. The information below should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found.

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	Gross Wells			Net Wells
	Productive	Dry	Total	Productive	Dry	Total
2021
Development	57	-	57	34.4	-	34.4
Exploratory	-	-	-	-	-	-
Total	57	-	57	34.4	-	34.4
2020
Development	54	-	54	30.4	-	30.4
Exploratory	-	-	-	-	-	-
Total	54	-	54	30.4	-	30.4
2019
Development	208	2	210	93.9	0.1	94.0
Exploratory	-	-	-	-	-	-
Total	208	2	210	93.9	0.1	94.0

As of December 31, 2021, we had two operated drilling rigs active on our properties. As of December 31, 2021, we had 50 gross (22.4 net) operated and non-operated wells in the process of drilling, completing or waiting on completion.

Hydraulic Fracturing

Hydraulic fracturing is a common practice in the oil and gas industry that is used to stimulate production of hydrocarbons from tight oil and gas formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. This process has typically been regulated by state oil and gas commissions. However, as described in more detail in “Business – Regulation – Environmental Regulations – Hydraulic Fracturing” in Item 1 of this Annual Report on Form 10-K, the EPA continues to consider the regulation of hydraulic fracturing, other federal agencies are examining hydraulic fracturing, and federal legislation is pending with respect to hydraulic fracturing. We have utilized hydraulic fracturing in the completion of our wells in our most active areas located in the states of North Dakota and Montana and we plan to continue to utilize this completion methodology.

Substantially all of our 64.0 MMBOE of proved undeveloped reserves are expected to be developed through the use of hydraulic fracture treatments.

We are not aware of any environmental incidents, citations or suits that have occurred during the last three years related to hydraulic fracturing operations involving oil and gas properties that we operate or in which we own a non-operated interest.

In order to minimize environmental impacts from hydraulic fracture treatments, we have taken the following steps:

●	we follow fracturing and flowback procedures that comply with or exceed North Dakota Industrial Commission or other state requirements;

●	we train all company and contract personnel who are responsible for well preparation, fracture stimulation and flowback on our procedures;

●	we routinely run casing caliper logs and/or ultrasonic logs on intermediate casing, pressure test the casing, and match maximum fracturing pressure limitations with the condition of the casing;

●	we construct berming around the outside portion of all our well locations which is in place prior to initiating fracturing operations;

●	we run tie-back fracturing strings on wells that have casing wear or cement tops that necessitate additional protection to meet state requirements;

●	we conduct annual emergency incident response drills in our active areas;

●

we are a member of the Sakakawea Area Spill Response LLC (“SASR”), which is comprised of 17 oil and gas related companies operating in the Missouri River and Lake Sakakawea regions of North Dakota. Members agree to share spill response resources and maintain SASR-owned water response equipment that can be accessed quickly in the early stages of a spill; and

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●

we participate in a voluntary baseline groundwater sampling program that is executed prior to drilling each well, even when no regulatory requirement exists, to ensure our operations do not negatively impact local groundwater resources. This program involves a thorough evaluation of potential groundwater sources within a half-mile radius, sampling prior to setting the well conductor and follow-up samples within one year of well completion.

While we do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations, we do have general liability and excess liability insurance policies that we believe would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Delivery Commitments

Our production sales agreements contain customary terms and conditions for the oil and natural gas industry, generally provide for sales based on prevailing market prices in the area, and generally have terms of one year or less.

We have one physical delivery contract effective as of December 31, 2021 which is tied to oil production at our Sanish field in Mountrail County, North Dakota for a term ending May 31, 2024. Under the terms of the contract, we are required to deliver 15,000 barrels of oil per day during the delivery term. If we fail to deliver the committed volumes we will be required to pay a deficiency payment of approximately $7.00 per undelivered Bbl, subject to upward adjustment, over the duration of the contract. We believe that our production and reserves are sufficient to fulfill the delivery commitment at our Sanish field, and we therefore expect to avoid any payments for deficiencies under this contract. However, a default on this contract could have a material impact on our business, financial condition, results of operations and cash flows.

We have another physical delivery contract effective as of December 31, 2021 which is tied to oil production in North Dakota and Montana for a term ending June 30, 2024. Under the terms of the contract, we are required to deliver 5,000 barrels of oil per day during the delivery term. If we fail to deliver any of the committed volumes during the term of the contract, we will be in immediate default under the contract and will be required to pay liquidated damages for the remaining term of the contract. We believe that our production and reserves are sufficient to fulfill this delivery commitment, and we therefore expect to avoid any payments for deficiencies under this contract. However, a default on this contract could have a material impact on our business, financial condition, results of operations and cash flows.

The following table summarizes these commitments as of December 31, 2021:


	Contracted	As a Percentage of
	Crude Oil Volumes	Total 2021
Period	(Bbl)	Production
Jan - Dec 2022	7,300,000	22%
Jan - Dec 2023	7,300,000	22%
Jan - Jun 2024	3,190,000	11%

We previously committed to deliver oil from our Redtail field in Weld County, Colorado under two physical delivery contracts, one of which expired in February 2018 and the other in April 2020. We were unable to deliver the committed volumes under these contracts and thus incurred deficiency fees of $24 million and $64 million during the 2020 Predecessor Period and the year ended December 31, 2019, respectively.

Item 3. Legal Proceedings

The information contained in the “Commitments and Contingencies” footnote under the headings “Chapter 11 Cases” and “Litigation” in the notes to the consolidated financial statements in Item 8 of this Annual Report on Form 10-K is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following table sets forth certain information, as of February 17, 2022, regarding the executive officers of Whiting Petroleum Corporation:


Name	Age	Position
Lynn A. Peterson	68	President and Chief Executive Officer
Charles J. Rimer	64	Executive Vice President, Operations and Chief Operating Officer
James P. Henderson	56	Executive Vice President, Finance and Chief Financial Officer
Sirikka R. Lohoefener	43	Vice President, Accounting and Controller
M. Scott Regan	51	Vice President, Legal, General Counsel and Secretary

The following biographies describe the business experience of our executive officers:

Lynn A. Peterson joined us in September 2020 as President and Chief Executive Officer. Mr. Peterson has 41 years of experience in the oil and gas industry. Prior to joining Whiting, Mr. Peterson was the Chairman of the Board, Chief Executive Officer and President of SRC Energy from 2015 until the closing of its merger with PDC Energy in January 2020. From January 2020 until September 2020 he was a private investor. He was a co-founder of Kodiak Oil & Gas Corporation (“Kodiak”) and served Kodiak as a director (2001-2014) and as its President and Chief Executive Officer (2002-2014) and Chairman of the Board (2011-2014) until its acquisition by Whiting in 2014. He also previously served as a director at Whiting from December 2014 to June 2015. Mr. Peterson holds a Bachelor of Science degree in accounting from the University of Northern Colorado.

Charles J. Rimer joined us in November 2018 as Chief Operating Officer. Mr. Rimer has 39 years of experience in the industry. Prior to joining Whiting, he was Senior Vice President, U.S. Onshore at Noble Energy, Inc. from 2017 to November 2018. Additionally, he held various management and technical positions during his 16 years at Noble Energy, Inc. including Senior Vice President, Global Services; Senior Vice President, Global EHSR and Operations Services; Vice President of Operations Services; among others. He also held various management and technical positions at Aspect Resources, Vastar Resources and ARCO Oil & Gas Company where he began his career in 1983. Mr. Rimer holds a Bachelor of Arts degree in business from Furman University and a Bachelor of Science degree in petroleum engineering from the University of Texas.

James P. Henderson joined us in September 2020 as Executive Vice President Finance and Chief Financial Officer. Mr. Henderson has 31 years of oil and gas experience. Prior to joining Whiting, Mr. Henderson served as Chief Financial Officer of SRC Energy from 2015 until the closing of its merger with PDC Energy in January 2020. From January 2020 until September 2020 he was a private investor. He also served as Chief Financial Officer of Kodiak until its acquisition by Whiting in 2014. Prior to joining Kodiak, Mr. Henderson held various positions at Aspect Energy, Anadarko Petroleum, Western Gas Resources, Apache Corporation and Pennzoil Company. He holds a Bachelor of Business Administration degree in accounting from Texas Tech University and a Master of Business Administration degree in finance from Regis University.

Sirikka R. Lohoefener joined us in June 2006 as a Senior Financial Accountant, became Financial Reporting Manager in January 2011 and Controller in March 2015. She was appointed Controller and Treasurer in March 2017, Vice President, Controller and Treasurer in December 2018 and Vice President, Accounting and Controller in October 2019 and serves as the Company’s designated principal accounting officer. Prior to joining Whiting, Ms. Lohoefener spent five years with Wagner, Burke & Barnes, LLP, a public accounting firm previously based in Golden, Colorado. She holds a Master of Accountancy degree from the University of Missouri and is a Certified Public Accountant.

M. Scott Regan joined us in November 2015 as Deputy General Counsel and was appointed Vice President, Legal, General Counsel and Secretary in November 2020. He has 18 years of experience in the oil and gas industry. Prior to joining Whiting, Mr. Regan served in various positions in the legal department of Ovintiv, where he most recently served as Vice President, Legal, Western and Southern Operations. Mr. Regan began his legal career in 1996 with the law firm of Crowley, Haughey, Hanson, Tool & Dietrich (now Crowley Fleck) in Helena, Montana and joined Holland & Hart in Denver, Colorado in 1998. Mr. Regan has a Bachelor of Arts degree in history from Montana State University and a Juris Doctor degree from the University of Montana School of Law.

Executive officers are elected by, and serve at the discretion of, the Board. There are no family relationships between any of our directors or executive officers.

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The following graph compares on a cumulative basis changes since September 2, 2020 (first full trading day post-bankruptcy) in (a) the total stockholder return on our common stock with (b) the total return on the Standard & Poor’s Composite 500 Index and (c) the total return on the Dow Jones U.S. Exploration & Production Index. Such changes have been measured by dividing (a) the sum of (i) the cumulative amount of dividends for the measurement period, assuming dividend reinvestment, and (ii) the difference between the price per share at the end of and the beginning of the measurement period, by (b) the price per share at the beginning of the measurement period. The graph assumes $100 was invested on September 2, 2020 at market closing in our common stock, the Standard & Poor’s Composite 500 Index and the Dow Jones U.S. Exploration & Production Index, respectively.


	9/2/2020		12/31/2020		3/31/2021		6/30/2021		9/30/2021		12/31/2021
Whiting Petroleum Corporation	$	100	$	128	$	182	$	280	$	300	$	332
Standard & Poor’s Composite 500 Index		100		105		111		120		120		133
Dow Jones U.S. Exploration & Production Index		100		114		152		175		177		189

Glossary of Certain Definitions		3

PART I

Item 1.	Business	7
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	37
Item 2.	Properties	38
Item 3.	Legal Proceedings	44
Item 4.	Mine Safety Disclosures	44
	Information about our Executive Officers	45

PART II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Reserved	49
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	63
Item 8.	Financial Statements and Supplementary Data	65
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	112
Item 9A.	Controls and Procedures	112
Item 9B.	Other Information	113
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	113

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	114
Item 11.	Executive Compensation	114
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	114
Item 13.	Certain Relationships, Related Transactions and Director Independence	114
Item 14.	Principal Accounting Fees and Services	115

PART IV

Item 15.	Exhibits and Financial Statement Schedules	115
Item 16.	Form 10-K Summary	115


	12/31/2016		12/31/2017		12/31/2018		12/31/2019		9/1/2020
Whiting Petroleum Corporation	$	100	$	55	$	47	$	15	$	1
Standard & Poor’s Composite 500 Index		100		119		112		144		158
Dow Jones U.S. Exploration & Production Index		100		100