Form 10-K UNIT CORP For: Dec 31

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March 31, 2022 3:30 PM EDT

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 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: 1-9260

UNIT CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

73-1283193

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

8200 South Unit Drive,

Tulsa,

Oklahoma

74132

(Address of principal executive offices)

(Zip Code)

(Registrant’s telephone number, including area code) (918) 493-7700

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


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
N/A	N/A	N/A

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 Section 15(d) of the Exchange 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 ☒ *

* Effective January 1, 2021, the registrant's obligations to file reports under Section 15(d) of the Exchange Act were automatically suspended.

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 ☐ Accelerated filer ☐ Non-accelerated filer ☒

Smaller reporting company ☒ Emerging growth company ☐

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 has filed all documents and reports required to be filed by Section 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 ☐

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

As of June 30, 2021, the aggregate market value of the voting and non-voting common equity (based on the closing price of the stock on the OTC Pink on June 30, 2021) held by non-affiliates was approximately $127.7 million. Determination of stock ownership by non-affiliates was made solely for the purpose of this requirement, and the registrant is not bound by these determinations for any other purpose.

As of March 31, 2022, 10,050,561 shares of the registrant’s common stock were outstanding.

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FORM 10-K

UNIT CORPORATION

TABLE OF CONTENTS


		Page

	PART I

Item 1.	Business	1

Item 1A.	Risk Factors	17

Item 1B.	Unresolved Staff Comments	31

Item 2.	Properties	31

Item 3.	Legal Proceedings	31

Item 4.	Mine Safety Disclosures	31

	PART II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	32

Item 6.	[Reserved]	33

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	34

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	48

Item 8.	Financial Statements and Supplementary Data	49

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	117

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	119

Item 13.	Certain Relationships and Related Transactions, and Director Independence	123

Item 14.	Principal Accountant Fees and Services	124

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	125
Item 16.	Form 10-K Summary	127
Signatures		128

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The following are explanations of some of the industry and general terms we use in this report:

ARO – Asset retirement obligations.

ASC – FASB Accounting Standards Codification.

ASU – Accounting Standards Update.

Bbl – Barrel, or 42 U.S. gallons liquid volume.

Boe – Barrel of oil equivalent. Determined using the ratio of six Mcf of natural gas to one barrel of crude oil or NGLs.

Btu – British thermal unit, used in gas volumes. Btu is used to refer to the natural gas required to raise the temperature of one pound of water by one-degree Fahrenheit at one atmospheric pressure.

Development drilling – The drilling of a well within the proven area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

DD&A – Depreciation, depletion, and amortization.

FASB – Financial and Accounting Standards Board.

FERC – Federal Energy Regulatory Commission.

Finding and development costs – Costs associated with acquiring and developing proved natural gas and oil reserves capitalized under generally accepted accounting principles, including any capitalized general and administrative expenses.

G&A – General and administrative expenses.

Gross acres or gross wells – The total acres or wells in which a working interest is owned.

IF – Inside FERC (U.S. Federal Energy Regulatory Commission).

LIBOR – London Interbank Offered Rate.

LOE – Lease operating expense.

MBbls – Thousand barrels of crude oil or other liquid hydrocarbons.

Mcf – Thousand cubic feet of natural gas.

MBoe – Thousand barrels of oil equivalent.

MMBtu – Million Btu’s.

MMcf – Million cubic feet of natural gas.

MMcfe – Million cubic feet of natural gas equivalent. It is determined using the ratio of one barrel of crude oil or NGLs to six Mcf of natural gas.

Net acres or net wells – The total fractional working interests owned in gross acres or gross wells.

NGLs – Natural gas liquids.

NYMEX – The New York Mercantile Exchange.

OPEC – The Organization of Petroleum Exporting Countries.

Play – A term applied by geologists and geophysicists identifying an area with potential oil and gas reserves.

Producing property – A natural gas or oil property with existing production.

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Proved developed reserves – Reserves 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; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate. For additional information, see the SEC’s definition in Rule 4-10(a)(6) of Regulation S-X.

Proved reserves – Proved oil and gas reserves are those quantities of oil and gas, 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 the 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. For additional information, see the SEC’s definition in Rule 4-10(a)(22)(i) through (v) of Regulation S-X.

Proved undeveloped reserves – Proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For additional information, see the SEC’s definition in Rule 4-10(a)(431) of Regulation S-X.

Reasonable certainty (regarding reserves) – If deterministic methods are used, reasonable certainty means high confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.

Reliable technology – A grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Ryder Scott – Ryder Scott Company, L.P., independent petroleum consultants.

SARs – Stock appreciation rights.

SEC – Securities and Exchange Commission.

SOFR - Secured Overnight Financing Rate.

Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to the point that would permit the production of economic quantities of natural gas or oil regardless of whether the acreage contains proved reserves.

The following are explanations of some of the terms we use that are specific to us:

2011 Notes – The $250.0 million 6.625% senior subordinated notes due 2021 issued in 2011.

2012 Notes – The $400.0 million 6.625% senior subordinated notes due 2021 issued in 2012.

BOKF – Bank of Oklahoma Financial Corporation.

Chapter 11 Cases – The cases filed by the Debtors on May 22, 2020 under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. The Chapter 11 proceedings were jointly administered under the caption In re Unit Corporation, et al. Case No. 20-32740 (DRJ). During the pendency of the Chapter 11 Cases, the Debtors operated their business as "debtors-in-possession" under the authority of the bankruptcy court and under the Bankruptcy Code. The Debtors emerged from bankruptcy on September 3, 2020.

Debtors – Unit and its wholly owned subsidiaries UDC, UPC, 8200 Unit, Unit Drilling Colombia, and Unit Drilling USA, all of which were parties to the Chapter 11 Cases.

DIP Credit Agreement – The credit agreement the company entered into on May 27, 2020 with the lenders under its then existing Unit credit agreement.

Effective Date – September 3, 2020, the date the Debtors emerged from bankruptcy.

Exit Credit Agreement – The credit agreement the company entered into on September 3, 2020 with the lenders replacing the DIP Credit Agreement and the Unit credit agreement.

MSA – The Amended and Restated Master Services and Operating Agreement for Superior.

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New Common Stock – The company common stock issued under the Plan and following the Effective Date.

Plan – The Chapter 11 plan of reorganization (including all exhibits and schedules, as amended, supplemented, or modified) and the related disclosure statement we filed with the bankruptcy court on June 9, 2020.

Predecessor – The company before the Effective Date.

Old Common Stock – The company's common stock existing immediately before the company filed for bankruptcy protection. As part of the Plan, the Old Common Stock was terminated as of the Effective Date.

Predecessor Period – Relates to the financial position and results of operations of the company for the period of January 1, 2020 through August 31, 2020.

Successor Period – Relates to the financial position and results of operations of the company for the period of September 1, 2020 through December 31, 2021.

Superior – Our 50% owned subsidiary Superior Pipeline Company, L.L.C., and its subsidiaries.

The Notes – Collectively, the 2011 Notes and 2012 Notes.

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FORWARD-LOOKING STATEMENTS/CAUTIONARY STATEMENTS

This report contains “forward-looking statements” – meaning, statements related to future events within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Other than statements of historical facts, included or incorporated by reference in this document addressing activities, events, or developments we expect or anticipate will or may occur, are forward-looking statements. Forward-looking statements often contain words such as “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions. This report modifies and supersedes documents filed by us before this report. Also, certain information we file with the SEC will automatically update and supersede information in this report.

Forward-looking statements are not guarantees of performance. They involve risks, uncertainties, and assumptions. Future actions, conditions or events, and future results may differ materially from those expressed in our forward-looking statements. Many factors that will determine these results are beyond our ability to control or accurately predict. Specific factors that could cause actual results to differ from those in our forward-looking statements include:

•the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;

•prices for oil, NGLs, and natural gas;

•demand for oil, NGLs, and natural gas;

•our exploration and drilling prospects;

•the estimates of our proved oil, NGLs, and natural gas reserves;

•oil, NGLs, and natural gas reserve potential;

•development and infill drilling potential;

•expansion and other development trends in the oil and natural gas industry;

•our business strategy;

•our plans to maintain or increase the production of oil, NGLs, and natural gas;

•our ability, and the market's receptiveness, to execute a strategic divestiture process;

•our ability to utilize the benefits of net operating losses and other deferred tax assets against potential future taxable income, including those that may be generated by a strategic divestiture process;

•our ability to retain or recruit key personnel throughout a strategic divestiture process;

•the number of gathering systems and processing plants we may plan to construct or acquire;

•volumes and prices for the natural gas we gather and process;

•expansion and growth of our business and operations;

•demand for our drilling rigs and the rates we charge for the rigs;

•our belief that the outcome of our legal proceedings will not materially affect our financial results;

•our ability to timely secure third-party services used in completing our wells;

•our ability to transport or convey our oil, NGLs, or natural gas production to existing pipeline systems;

•the impact of federal and state legislative and regulatory actions affecting our costs and increasing operating restrictions or delays and other adverse impacts on our business;

•the possibility of security threats, including terrorist attacks and cybersecurity breaches, against or otherwise affecting our facilities and systems;

•any projected production guidelines we may issue;

•our anticipated capital budgets;

•our financial condition and liquidity;

•the number of wells our oil and natural gas segment plans to drill;

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•our estimates of any ceiling test write-downs or other potential asset impairments we may have to record in future periods; and

•our ability to carry out our post reorganization plans.

These statements are based on our assumptions and analyses considering our experience and our perception of historical trends, current conditions, expected future developments, and other factors we believe are appropriate in the circumstances. Whether actual results and developments will meet our expectations and predictions is subject to risks and uncertainties, any one or combination of which could cause our actual results to differ materially from our expectations and predictions. Some of these risks and uncertainties are:

•the risk factors discussed in this document and the documents (if any) we incorporate by reference;

•general economic, market, or business conditions;

•the availability and nature of (or lack of) business opportunities we pursue;

•demand for our land drilling services;

•changes in laws and regulations;

•changes in the current geopolitical situation, such as the current conflict occurring between Russia and Ukraine;

•risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;

•risks associated with future weather conditions;

•decreases or increases in commodity prices;

•the amount and terms of our debt;

•future compliance with covenants under our credit agreements;

•pandemics, epidemics, outbreaks, or other public health events, such as COVID-19; and

•other factors, most of which are beyond our control.

You should not construe this list to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that the actions, events, or results expressed in forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements. Except as required by law, we disclaim any obligation to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after this document to reflect incorrect assumptions or unanticipated events.

Additional discussion of factors that may affect our forward-looking statements appear elsewhere in this report, including in Item 1A “Risk Factors,” Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk-Energy Commodity Market Risk.”

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UNIT CORPORATION

Annual Report

For The Year Ended December 31, 2021

PART I

Item 1. Business

Unless otherwise indicated or required by the context, the terms “company,” “Unit,” “us,” “our,” “we,” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our Mid-Stream segment refer to Superior Pipeline Company, L.L.C. (and its subsidiaries) of which we own 50%.

Our executive offices are at 8200 South Unit Drive, Tulsa, Oklahoma 74132; our telephone number is (918) 493-7700.

Information regarding our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports, will be provided free in print to any shareholders who request them. They are also available on our website at www.unitcorp.com, as soon as reasonably possible after we electronically file these reports with or furnish them to the SEC. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information about us we file electronically with the SEC.

Our corporate governance guidelines and code of ethics are available for free on our website at www.unitcorp.com or in print to any shareholder who requests them. We may occasionally provide important disclosures to investors by posting them in the investor information section of our website, as allowed by SEC rules.

GENERAL

We were founded in 1963 as an oil and natural gas contract drilling company. Today, besides our drilling operations, we have operations in the exploration and production and mid-stream areas. We operate, manage, and analyze our results of operations through our three principal business segments:

•Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires, and produces oil and natural gas properties for our account. The company initiated an asset divestiture program at the beginning of 2021 to sell certain non-core oil and gas properties and reserves (the “Divestiture Program”). On October 4, 2021, the company announced that it is expanding the Divestiture Program to now include the potential sale of additional properties, including up to all of UPC’s oil and gas properties and reserves. On January 20, 2022, the company announced that it has retained a financial advisor and launched the process.

•Contract Drilling – carried out by our subsidiary Unit Drilling Company. This segment contracts to drill onshore oil and natural gas wells for others and our account.

•Mid-Stream – carried out by Superior. This segment buys, sells, gathers, processes, and treats natural gas for third parties and our account.

Each company may conduct operations through subsidiaries of its own. We also have several other subsidiaries, none of which conduct material operations.

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This table provides certain information about our assets as of December 31, 2021:


Oil and Natural Gas
Total number of wells in which we own an interest			5,253
Contract Drilling
Total number of drilling rigs available for use			21
Mid-Stream
Number of natural gas treatment plants we own			3
Number of processing plants we own			12
Number of natural gas gathering systems we own			18

Emergence From Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On May 22, 2020, the Debtors filed petitions for reorganization under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. The Chapter 11 proceedings were jointly administered under the caption In re Unit Corporation, et al., Case No. 20-32740 (DRJ). During the pendency of the Chapter 11 Cases, the Debtors operated their business as "debtors-in-possession" under the authority of the bankruptcy court and under the Bankruptcy Code.

The Debtors filed their Plan and the related disclosure statement with the bankruptcy court on June 9, 2020. On August 6, 2020, the bankruptcy court entered the “Findings of Fact, Conclusions of Law, and Order (I) Approving the Disclosure Statement on a Final Basis and (II) Confirming the Debtors’ Amended Joint Chapter 11 Plan of Reorganization” [Docket No. 340] (Confirmation Order) confirming the Plan. On September 3, 2020, the Debtors emerged from the Chapter 11 Cases.

2021 SEGMENT OPERATIONS HIGHLIGHTS

Oil and Natural Gas

•Revenues before eliminations increased by 69% from 2020 primarily due to higher average commodity pricing, partially offset by lower production volumes.

•Operating costs before eliminations decreased 43% from 2020.

•Capital expenditures increased 89% from 2020.

Contract Drilling

•Revenues decreased 18% from 2020 primarily due to the absence of 2020 rig termination and standby fees. Average rig utilization increased 8% to 10.9 rigs during 2021 while there was a 4% decrease in average dayrate to $17,987.

•Operating costs decreased 7% from 2020 primarily due to a decrease in rig fleet from 58 to 21 in 2021.

Mid-Stream

•Revenues before eliminations increased 87% and operating expenses before eliminations increased 114% from 2020 primarily due to higher commodity pricing, partially offset by lower volumes.

•Acquired a cryogenic processing plant, approximately 1,620 miles of low-pressure gathering pipeline, and related compressor stations located in southern Kansas in November 2021.

FINANCIAL INFORMATION ABOUT SEGMENTS

See Note 23 - Industry Segment Information of our Notes to Consolidated Financial Statements in Item 8 of this report for information about each of our segment’s revenues, profits or losses, and total assets.

OIL AND NATURAL GAS

General. All our oil and natural gas properties are in the United States. Our producing oil and natural gas properties, unproved properties, and related assets are mainly in Oklahoma and Texas, and to a lesser extent Kansas, Louisiana, Montana, North Dakota, Utah, and Wyoming.

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When we are the operator of a property, we try to use one of our drilling rigs to drill any wells on the property, and we also use our mid-stream segment to gather our gas if it is economical to do so.

This table presents certain information regarding our oil and natural gas operations as of December 31, 2021:


	Number of Gross Wells	Number of Net Wells	Number of Gross Wells in Process	Number of Net Wells in Process	2021 Average Net Daily Production
					Natural Gas (Mcf)	Oil (Bbls)	NGLs (Bbls)
Total	5,253	1,450.67	5	0.02	79,485	4,424	7,189

Dispositions. The company initiated an asset divestiture program at the beginning of 2021 to sell certain non-core oil and gas properties and reserves (the “Divestiture Program”). On October 4, 2021, the company announced that it is expanding the Divestiture Program to now include the potential sale of additional properties, including up to all of UPC’s oil and gas properties and reserves. On January 20, 2022, the company announced that it has retained a financial advisor and launched the process.

On March 8, 2022, the company closed on the sale of wells and related leases located near the Oklahoma Panhandle for $5.0 million, subject to customary closing and post-closing adjustments with an effective date of December 1, 2021. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.

On August 16, 2021, the company closed on the sale of substantially all of our wells and related leases located near Oklahoma City, Oklahoma for $19.5 million, subject to customary closing and post-closing adjustments. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.

On May 6, 2021, the company closed on the sale of substantially all of our wells and related leases located in Reno and Stafford Counties, Kansas for $7.1 million, subject to customary closing and post-closing adjustments. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.

We also sold $5.0 million of other non-core oil and natural gas assets, net of related expenses, during the year ended December 31, 2021. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.

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Well and Leasehold Data. The following tables identify certain information regarding our oil and natural gas exploratory and development drilling operations:


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020
	Gross	Net	Gross	Net	Gross	Net
Wells drilled:
Development:




Oil	10	3.7	2	0.3	10	0.1




Natural Gas	—	—	1	—	12	0.3




Dry	—	—	—	—	—	—
Total development	10	3.7	3	0.3	22	0.4
Exploratory:




Oil	13	0.7	—	—	—	—




Natural gas	—	—	—	—	—	—




Dry	1	—	—	—	—	—
Total exploratory	14	0.7	—	—	—	—
Total wells drilled	24	4.4	3	0.3	22	0.4


	Year Ended December 31,
	2021		2020
	Gross	Net	Gross	Net
Wells producing or capable of producing:




Oil	736	141.2	1,534	604.8




Natural gas	2,380	649.0	4,601	1,598.3
Total	3,116	790.2	6,135	2,203.1

We did not develop any previously booked proved undeveloped oil and natural gas reserves in 2021 or 2020.

The following table summarizes our leasehold acreage at December 31, 2021:

Developed

Undeveloped

Total

Gross

Net

Gross

Net (1)

Gross

Net

Total

489,308

270,457

8,470

4,212

497,778

274,669

_________________________

1.Approximately 100% of the net undeveloped acres are covered by leases that will expire in the years 2022—2024 unless drilling or production extends those leases.

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Price and Production Data. The following tables identify the average sales price, production volumes, and average production cost per equivalent barrel for our oil, NGLs, and natural gas production for the periods indicated:


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020
Average sales price per barrel of oil produced:
Price before derivatives	$	66.50	$	39.23	$	35.14
Effect of derivatives	(16.47)		(1.94)		(3.16)
Price including derivatives	$	50.03	$	37.29	$	31.98
Average sales price per barrel of NGLs produced:
Price before derivatives	$	23.41	$	9.28	$	4.83
Effect of derivatives	—		—		—
Price including derivatives	$	23.41	$	9.28	$	4.83
Average sales price per Mcf of natural gas produced:
Price before derivatives	$	3.55	$	1.91	$	1.11
Effect of derivatives	(0.62)		0.01		0.03
Price including derivatives	$	2.93	$	1.92	$	1.14


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020
Oil production (MBbls):

Jazz Wilcox field	126		61		184




Buffalo Wallow field	108		48		118
Mendota field	88		35		76
All other fields	1,293		482		1,184

Total oil production	1,615		626		1,562
NGLs production (MBbls):

Jazz Wilcox field	433		206		601




Buffalo Wallow field	581		261		618
Mendota field	437		155		327
All other fields	1,173		423		853

Total NGLs production	2,624		1,045		2,399
Natural gas production (MMcf):

Jazz Wilcox field	5,169		2,414		7,003




Buffalo Wallow field	5,860		2,651		6,214
Mendota field	2,623		967		2,059
All other fields	15,360		4,974		11,287

Total natural gas production	29,012		11,006		26,563
Total production (MBoe):

Jazz Wilcox field	1,420		669		1,952




Buffalo Wallow field	1,665		751		1,772
Mendota field	963		352		746
All other fields	5,026		1,734		3,918

Total production	9,074		3,506		8,388
Average production cost per equivalent Bbl (1)	$	5.56	$	5.27	$	4.86

_______________________

1.Excludes ad valorem taxes and gross production taxes.

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Our Buffalo Wallow field in Hemphill County, Texas, contained 20% and 16% of our total proved reserves in 2021 and 2020, respectively, expressed on an oil-equivalent barrels basis. Our Mendota field, in the Granite Wash play in the Texas Panhandle, contained 15% and 16% of our total proved reserves for those same years also expressed on an oil-equivalent barrels basis. There are no other fields that accounted for over 15% of our proved reserves.

Oil, NGLs, and Natural Gas Reserves. The table below identifies our estimated proved developed and undeveloped oil, NGLs, and natural gas reserves:


	Year Ended December 31, 2021
	Oil (MBbls)	NGLs (MBbls)	Natural Gas (MMcf)	Total Proved Reserves (MBoe)




Total proved developed	9,019	21,525	220,640	67,317




Total proved undeveloped	—	—	—	—
Total proved	9,019	21,525	220,640	67,317

Oil, NGLs, and natural gas reserves cannot be measured exactly. Estimates of those reserves require extensive judgments of reservoir engineering data and are generally less precise than other estimates made in financial disclosures.

Company Reserve Estimation and Technical Qualifications

Our Reservoir Engineering department is responsible for reserve determination for the wells in which we have an interest. Their primary objective is to estimate the wells' future reserves and future net value to us. Data is incorporated from multiple sources including geological, production engineering, marketing, production, land, and accounting departments. The engineers review this information for accuracy as it is incorporated into the reservoir engineering database. Management reviews our internal controls to help provide assurance all the data has been provided. New well reserve estimates are provided to management and the respective operational divisions for additional scrutiny. Major reserve changes on existing wells are reviewed regularly with the operational divisions to confirm completeness and accuracy. As the external audit is being completed, the reservoir department reviews all properties for accuracy of forecasting.

Responsibility for overseeing the preparation of our reserve report is shared by our reservoir engineers Derek Smith and Troy Pickens.

Mr. Smith received a Bachelor of Science in Petroleum Engineering with a Minor in Business from the University of Tulsa in 2005. He then worked for Apache Corporation through 2008 and joined Unit in 2009 as a Corporate Reserves Engineer involved in reserve evaluation, acquisition appraisals, and prospect reviews with increasing levels of responsibility. In 2020, he was given the responsibility of managing the Corporate Reserves. He has been a member of SPE since 2000 and joined the SPEE in 2018.

Mr. Pickens earned a Bachelor of Science degree in Mechanical Engineering with Minors in Math and Entrepreneurship from Baylor University in 2014. He began employment with Unit as an Engineering Intern in the Summers of 2012 and 2013 and joined the company full time as a Production Engineer in 2014. He worked as a production engineer over various company assets with increasing levels of responsibility through 2019. In 2019 he transitioned into a Reservoir Engineering role, where he has been involved in reserve evaluation, project and asset development planning, and acquisition and divestiture assessment.

As part of their continuing education Mr. Smith and Mr. Pickens have attended various seminars and forums to enhance their understanding of current standards and issues for reserves presentation. These forums have included those sponsored by various professional societies and professional service firms including Ryder Scott.

Ryder Scott Audit and Technical Qualifications

We use Ryder Scott to audit the reserves prepared by our reservoir engineers. Ryder Scott has been providing petroleum consulting services internationally since 1937. Their summary report is attached as Exhibit 99.1 to this Form 10-K. The wells or locations for which reserve estimates were audited were taken from our reserve and income projections as of December 31, 2021, and comprised approximately 85% of the total proved developed future net income discounted at 10% (based on the SEC's unescalated pricing policy).

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Mr. Robert J. Paradiso was the primary technical person responsible for overseeing the estimate of the reserves prepared by Ryder Scott.

Mr. Paradiso, an employee of Ryder Scott since 2008, is a Vice President and serves as Project Coordinator, responsible for coordinating and supervising staff and consulting engineers in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Paradiso served in several engineering positions with Getty Oil Company, Texaco, Union Texas Petroleum, Amax Oil and Gas, Inc., Norcen Explorer, Inc., Amerac Energy Corporation, Halliburton Energy Services, Santa Fe Snyder Corp., and Devon Energy Corporation.

Mr. Paradiso earned a Bachelor of Science degree in Petroleum Engineering from Texas Tech University in 1979 and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers (SPE).

Besides gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires at least fifteen hours of continuing education annually, including at least one hour in professional ethics, which Mr. Paradiso fulfills. Based on his educational background, professional training and over 41 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Paradiso has attained the professional qualifications as a Reserves Estimator and Reserves Auditor in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the SPE as of June 2019. For more information regarding Mr. Paradiso’s geographic and job-specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Company/Employees.

Definitions and Other Proved Reserve Information.

For proved reserves, the area of the reservoir considered as "proved" includes:

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

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

Absent data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as incurred in a well penetration unless geosciences, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

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

•Successful testing by a pilot project in an area of the reservoir with properties no more favorable than the reservoir as a whole;

•The operation of an installed program in the reservoir or other evidence using reliable technology establishes 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 used is the average of the prices over the 12 months before the ending date of the period covered by the report and is an unweighted arithmetic average of the first day of the month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions.

Proved Undeveloped Reserves. As of December 31, 2021, we had no proved undeveloped reserves.

Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2021 and 2020, the changes in quantities, and standardized measure of those reserves for the years then ended, are shown in the Supplemental Oil and Gas Disclosures in Item 8 of this report.

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Contracts. Our oil production is sold at or near our wells under purchase contracts at prevailing prices under arrangements customary in the oil industry. Our natural gas production is sold to intrastate and interstate pipelines and independent marketing firms under contracts with terms generally ranging from one month to a year. Few of these contracts contain provisions for readjustment of price as most are market sensitive.

Customers. One customer accounted for 11% of our oil and natural gas revenues during the year ended December 31, 2021 and no other company accounted for over 10% of our oil and natural gas revenues besides our mid-stream segment. Our mid-stream segment purchased $48.0 million of our natural gas and NGLs production and provided gathering and transportation services of $3.3 million. Intercompany revenue from services and purchases of production between our mid-stream segment and our oil and natural gas segment has been eliminated in our consolidated financial statements.

CONTRACT DRILLING

General. Our contract drilling business is conducted through Unit Drilling Company. Through this company we drill onshore oil and natural gas wells for ourselves and for others. Our drilling operations are mainly in Oklahoma, Texas, and New Mexico.

The following table identifies certain information about our contract drilling segment assets and activity:


	Successor						Predecessor
	Year Ended December 31, 2021			Four Months Ended December 31, 2020			Eight Months Ended August 31, 2020
Number of drilling rigs available for use	21			58			58
Average number of drilling rigs owned	30			58			58
Average number of drilling rigs utilized	10.9			7.2			11.5
Utilization rate (1)	36		%	12		%	20		%
Average revenue per day (2)	$	19,097		$	21,974		$	26,106
Total footage drilled (feet in 1,000’s)	4,487			1,062			2,999
Number of wells drilled	251			67			179

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1.Utilization rate is determined by dividing the average number of drilling rigs used by the average number of drilling rigs available for use during the year. See Drilling Rig Fleet below for discussion on the 2021 reduction in drilling rigs available for use.

2.Represents the total revenues from our contract drilling segment divided by the total days our drilling rigs were used during the year.

Description and Location of Our Drilling Rigs. An on-shore drilling rig is composed of major equipment components like engines, drawworks or hoists, derrick or mast, substructure, mud pumps, blowout preventers, top drives, and drill pipe. Because of the normal wear and tear from operating 24 hours a day, several of the major components, like engines, mud pumps, top drives, and drill pipe, must be replaced or overhauled periodically. Other major components, like the substructure, mast, and drawworks, can be used for extended periods with proper inspections and maintenance. We also own additional equipment used in operating our drilling rigs, including iron roughnecks, automated catwalks, skidding systems, large air compressors, trucks, and other support equipment. The maximum depth capacities of our various drilling rigs range from 9,500 to 40,000 feet allowing us to cover a wide range of our customers' drilling requirements.

The following table shows certain information about our drilling rigs as of December 31, 2021:


	Contracted Rigs	Non-Contracted Rigs	Total Rigs	Average Rated Drilling Depth (ft)


Drilling Rigs	16	5	21	20,238

Fluctuating commodity prices directly affect the number of drilling rigs we can put to work, both positively and negatively. Generally, sustained higher commodity prices lead to greater demand for drilling rigs, while demand and rates tends to fall as commodity prices decline for any extended period. Drilling rig utilization increased during 2021 as commodity prices increased. The number of drilling rigs we can work also depends on several conditions besides demand, including the availability of qualified labor as well as the availability of needed drilling supplies and equipment.

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The following table shows the average number of our drilling rigs working by quarter for the years indicated:


	2021	2020
First quarter	9.4	18.7
Second quarter	10.0	9.1
Third quarter	11.0	5.1
Fourth quarter	13.2	7.6

Drilling Rig Fleet. We reduced the number of drilling rigs available for use from 58 at December 31, 2020 to 21 during the second quarter of 2021 in order to focus on utilization of our BOSS drilling rigs and certain SCR rigs that are either currently under contract or candidates for future upgrades.

Dispositions. We sold non-core contract drilling assets for proceeds of $12.7 million, net of related expenses, resulting in net gains of $10.1 million during the year ended December 31, 2021.

Drilling Contracts. Our third-party drilling contracts are generally obtained through competitive bidding on a well-by-well basis. Contract terms and payment rates vary depending on the type of contract used, the duration of the work, the equipment and services supplied, and other matters. We pay certain operating expenses, including the wages of our drilling rig personnel, maintenance expenses, and incidental drilling rig supplies and equipment. The contracts are usually subject to early termination by the customer subject to the payment of a fee. Our contracts also contain provisions regarding indemnification against certain types of claims involving injury to persons, property, and for acts of pollution. The specific terms of these indemnifications are negotiated on a contract-by-contract basis.

Most of our drilling contracts during 2021 and 2020 were daywork contracts. Under a daywork contract, we provide the drilling rig with the required personnel and the operator supervises the drilling of the well. Our daywork compensation is based on a negotiated rate to be paid for each day the drilling rig is used.

Most of our contracts are term contracts, with the rest being well-to-well contracts. Term contracts can range from months to multiple years and the rates can either be fixed throughout the term or allow for periodic adjustments.

Customers. Five customers accounted for 79% of our contract drilling revenues during the year ended December 31, 2021. No other third-party customer accounted for 10% or more of our contract drilling revenues.

Our contract drilling segment may also provide drilling services for our oil and natural gas segment. The contract drilling segment did not drill any wells for our oil and natural gas segment in 2021. Depending on the timing of the drilling services performed on our properties, those services may be deemed, for financial reporting purposes, to be associated with acquiring an ownership interest in the property. Revenues and expenses for these services are eliminated in our statement of operations, with any profit recognized reducing our investment in our oil and natural gas properties.

MID-STREAM

General. Our mid-stream operations are conducted through Superior Pipeline Company, L.L.C. and its subsidiaries, of which we presently own a 50% interest. Superior's operations consist of buying, selling, gathering, processing, and treating natural gas. It operates 3 natural gas treatment plants, 12 processing plants, 18 active gathering systems, and approximately 3,822 miles of pipeline. Superior and its subsidiaries operate in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

Superior is governed and managed under the Amended and Restated Limited Liability Company Agreement (Agreement) and a Management Services Agreement (MSA). The MSA is between our wholly-owned subsidiary, SPC Midstream Operating, L.L.C. (the Operator) and Superior. As the Operator, we provide services, such as operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $0.3 million.

The Agreement specifies how future distributions are to be allocated among the Members. Distributions from Available Cash (as defined in the Agreement) were generally split evenly between the Members prior to December 31, 2021, when the three-year period for Unit's commitment to spend $150.0 million (Drilling Commitment Amount) to drill wells in the Granite Wash/Buffalo Wallow area ended. The total amount spent by Unit towards the Drilling Commitment Amount was $24.6 million. Accordingly, SP Investor will receive 100% of Available Cash distributions related to periods subsequent to December 31, 2021 until the $72.7 million Drilling Commitment Adjustment Amount (as defined in the Agreement) is satisfied.

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After April 1, 2023, either Member may initiate a sale process of Superior to a third-party or a liquidation of Superior's assets (Sale Event). In a Sale Event, the Agreement generally requires cumulative distributions to SP Investor in excess of its original $300.0 million investment sufficient to provide SP Investor a 7% internal rate of return on its capital contributions to Superior before any liquidation distribution is made to Unit. As of December 31, 2021, liquidation distributions paid first to SP Investor of $361.7 million would be required for SP Investor to reach its 7% Liquidation IRR Hurdle at which point Unit would then be entitled to receive up to $361.7 million of the remaining liquidation distributions to satisfy Unit's 7% Liquidation IRR Hurdle with any remaining liquidation distributions paid as outlined within the Agreement.

Effective March 1, 2022, the employees of the Operator were transferred to Superior and the MSA was amended and restated to remove the operating services the Operator was providing to Superior. There was no change to the monthly service fee for shared services. The power to direct the activities that most significantly affect Superior's operating performance is now shared by the equity holders (Unit Corporation and SP Investor) rather than held by the Operator. Superior no longer qualifies as a VIE subsequent to these amendments and we will no longer consolidate the financial position, operating results, and cash flows of Superior as of March 1, 2022. We will subsequently account for our investment in Superior as an equity method investment under the HLBV method.

The following table presents certain information regarding our mid-stream segment for the periods indicated:


	Successor		Predecessor
	Year Ended December 31, 2021	Four Months Ended December 31, 2020	Eight Months Ended August 31, 2020
Gas gathered—Mcf/day	319,394	324,892	388,506
Gas processed—Mcf/day	130,000	135,615	158,031
NGLs sold—gallons/day	442,796	441,761	612,301

Dispositions and Acquisitions. In November 2021, we closed on an acquisition for $13.0 million, subject to customary closing and post-closing adjustments, that included a cryogenic processing plant, approximately 1,620 miles of low-pressure gathering pipeline, and related compressor stations located in southern Kansas.

Impairment. In December 2021, we determined that the carrying value of a gathering system in Pennsylvania was not recoverable and exceeded its estimated fair value due to unfavorable forecasted economics. We recorded non-cash impairment charges of $10.7 million based on the estimated fair value of the asset group.

Contracts. Our mid-stream segment provides its customers with a full range of gathering, processing, and treating services. These services are usually provided to each customer under long-term contracts (more than one year), but we also have short-term contracts. Our customer agreements include these types of contracts:

•Fee-Based Contracts. These contracts provide for a set fee for gathering, transporting, compressing, and treating services. Our mid-stream’s revenue is a function of the volume of natural gas and is not directly dependent on the value of natural gas. For the year ended December 31, 2021, 76% of our mid-stream segment’s total volumes and 73% of its operating margins (as defined below) were under fee-based contracts.

•Commodity-Based Contracts. These contracts consist of several contract structure types. Under these contract structures, our mid-stream segment purchases the raw well-head natural gas and settles with the producer at a stipulated price while retaining all sales proceeds from third parties or retains a negotiated percentage of the sales proceeds from the residue natural gas and NGLs it gathers and processes, with the remainder being paid to the producer. For the year ended December 31, 2021, 24% of our mid-stream segment’s total volumes and 27% of operating margins (as defined below) were under commodity-based contracts.

For each of the above contract types, operating margin is defined as total operating revenues less operating expenses and does not include depreciation, amortization, and impairment, general and administrative expenses, interest expense, or income taxes.

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Customers. Three customers accounted for 58% of our mid-stream revenues. We believe that there are other customers available to purchase our natural gas and NGLs if we were to lose these customers. Superior purchased $48.0 million of our oil and natural gas segment's natural gas and NGLs production, and provided gathering and transportation services of $3.3 million. Intercompany revenue from services and purchases of production between Superior and our oil and natural gas segment has been eliminated in our consolidated financial statements.

COMPETITION

All our businesses are highly competitive and price sensitive. Competition in the contract drilling business traditionally involves factors such as demand, price, efficiency, the condition of equipment, availability of labor and equipment, reputation, and customer relations.

Our oil and natural gas operations likewise encounter strong competition from other oil and natural gas companies. Many competitors have greater financial, technical, and other resources than we do and have more experience than we do in the exploration for and production of oil and natural gas.

Our drilling success and the success of other activities integral to our operations will depend, in part, during times of increased competition on our ability to attract and retain experienced geologists, engineers, and other professionals. Competition for these professionals can be intense.

Our mid-stream segment competes with purchasers and gatherers of all types and sizes, including those affiliated with various producers, other major pipeline companies, and independent gatherers for the right to purchase natural gas and NGLs, build gathering and processing systems, and deliver the natural gas and NGLs once the gathering and processing systems are established. The principal elements of competition include the rates, terms, and availability of services, reputation, and the flexibility and reliability of service.

HUMAN CAPITAL

We believe that our employees are critical to our future success, and seek to provide competitive compensation and benefits in order to attract and retain a skilled workforce. We care about the well-being and development of our employees, and aim to provide a culture of respect and collaboration by supporting employee training and development. We are also very focused on maintaining a culture of continuous improvement in safety and environmental practices - safety and environmental stewardship are at the forefront of everything that we do.

As of March 3, 2022, we had 788 employees, none of whom are members of a union or labor organization. Our workforce includes 478 employees in our contract drilling segment, 136 employees in our oil and natural gas segment, 128 employees in our mid-stream segment, and 46 in our general corporate group. We also periodically utilize the services of independent contractors. We have not experienced any strikes or work-force stoppages.

GOVERNMENTAL REGULATIONS

General. Our business depends on the demand for services from the oil and natural gas exploration and development industry, and therefore our business can be affected by political developments and changes in laws and regulations that control or curtail drilling for oil and natural gas for economic, environmental, or other policy reasons.

Various state and federal regulations affect the production and sale of oil and natural gas. All states in which we conduct activities impose varying restrictions on the drilling, production, transportation, and sale of oil and natural gas. This discussion of certain laws and regulations affecting our operations should not be relied on as an exhaustive review of all regulatory considerations affecting us, due to the multitude of complex federal, state, and local regulations, and their susceptibility to change at any time by later agency actions and court rulings that may affect our operations.

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Natural Gas Sales and Transportation. Under the Natural Gas Act of 1938, FERC regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. FERC’s authority over interstate natural gas sales has been substantially modified by the Natural Gas Policy Act under which FERC continued to regulate the maximum selling prices of certain categories of gas sold in “first sales” in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the Decontrol Act) deregulated natural gas prices for all “first sales” of natural gas. Because “first sales” include typical wellhead sales by producers, all-natural gas produced from our natural gas properties is sold at market prices, subject to the terms of any private contracts which may be in effect. FERC’s authority over interstate natural gas transportation is not affected by the Decontrol Act.

Our sales of natural gas are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes are intended by FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of natural gas to the primary role of gas transporters. All-natural gas marketing by the pipelines must divest to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants. Because of the various omnibus rulemaking proceedings in the late 1980s and the later individual pipeline restructuring proceedings of the early to mid-1990s, interstate pipelines must provide open and nondiscriminatory transportation and transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end users, and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate services, FERC expanded the impact of open access regulations to certain aspects of intrastate commerce.

FERC has pursued other policy initiatives that affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to using electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information timely and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services on the pipeline’s demonstration of lack of market control in the relevant service market.

Because of these changes, independent sellers and buyers of natural gas have gained direct access to the pipeline services they need and can better conduct business with a larger number of counter parties. These changes generally have improved the access to markets for natural gas while substantially increasing competition in the natural gas marketplace. However, we cannot predict what new or different regulations FERC and other regulatory agencies may adopt or what effect later regulations may have on production and marketing of natural gas from our properties.

Although in the past Congress has been very active in natural gas regulation as discussed above, the more recent trend has been for deregulation and the promotion of competition in the natural gas industry. In addition to “first sales” deregulation, Congress also repealed incremental pricing requirements and natural gas use restraints previously applicable. There continually are legislative proposals pending in the Federal and state legislatures which, if enacted, would significantly affect the petroleum industry. It is impossible to predict what proposals might be enacted by Congress or the various state legislatures and what effect these proposals might have on the production and marketing of natural gas by us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue or what the ultimate effect will be on the production and marketing of natural gas by us cannot be predicted.

Oil and Natural Gas Liquids Sales and Transportation. Our sales of oil and natural gas liquids currently are not regulated and are at market prices. The prices received from the sale of these products are affected by the cost of transporting these products to market. Much of that transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments could cause decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, FERC examines the relationship between the annual change in the index and the actual cost changes experienced by the oil pipeline industry and makes any necessary adjustment in the index to be used during the ensuing five years. We cannot predict with certainty what effect the periodic review of the index by FERC will have on us.

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Exploration and Production Activities. Federal, state, and local agencies also have promulgated extensive rules and regulations applicable to our oil and natural gas exploration, production, and related operations. The states we operate in require permits for drilling operations, drilling bonds, and filing reports about operations and impose other requirements relating to the exploration of oil and natural gas. Many states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells, and regulating spacing, plugging and, abandonment of such wells. The statutes and regulations of some states limit the rate at which oil and natural gas is produced from our properties. The federal and state regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are amended or reinterpreted frequently, we cannot predict the future cost or impact of complying with these laws.

Environmental.

General. Our operations are subject to federal, state, and local laws and regulations governing protection of the environment. These laws and regulations may require acquisition of permits before certain of our operations may be commenced and may restrict the types, quantities, and concentrations of various substances that can be released into the environment. Planning and implementation of protective measures must prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids, and other substances may subject us to penalties and cleanup requirements. Handling, storage, and disposal of both hazardous and non-hazardous wastes are subject to regulatory requirements.

The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act (RCRA), and their state counterparts, are the primary vehicles for imposition of such requirements and for civil, criminal, and administrative penalties and other sanctions for violation of their requirements. In addition, the federal Comprehensive Environmental Response Compensation and Liability Act (CERCLA) and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons considered responsible for the release of hazardous substances into the environment. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of remedial action and damages to natural resources. The Oil Pollution Act of 1990 amends the Clean Water Act and establishes strict liability for owners and operators of

facilities that cause a release of oil into waters of the United States. In addition, this law requires owners and operators of

facilities that store oil above specified threshold amounts to develop and implement spill prevention, control and

countermeasure plans.

Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gaswastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the U.S. Environmental Protection Agency (EPA) or a state equivalent agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (Corps). The scope of the Clean Water Act’s jurisdiction has been the subject of significant uncertainty and litigation in recent years. For example, under the Obama Administration, the EPA and the U.S. Army Corp of Engineers proposed a new expansive definition of the “waters of the United States,” known as the “Clean Water Rule.” However, during the Trump Administration, the EPA and the Corps replaced the Clean Water Rule with the Navigable Waters Protection Rule (NWPR), which narrows the definition of “waters of the United States” to four categories of jurisdictional waters and includes twelve categories of exclusions, including groundwater; however, these rulemakings are currently subject to litigation and it is possible that the Biden Administration could propose a broader definition for these regulated waters. Both the Clean Water Rule and the NWPR are subject to ongoing litigation, with the Clean Water Rule in effect in certain states and the NWPR in effect in others. In addition, in an April 2020 decision defining the scope of the Clean Water Act that was handed down just days after the NWPR was published, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the Clean Water Act and require a permit. The Court rejected the EPA’s and Corps’ assertion that groundwater should be totally excluded from the Clean Water Act. The Court’s decision is expected to bolster challenges to the NWPR.” As a result of these developments, the scope of jurisdiction under the Clean Water Act is uncertain at this time.

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To the extent any rule expands the scope of the Clean Water Act’s jurisdiction in areas where we operate, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of our natural gas and oil projects. Similarly, any increased costs or delays for such permits may impact the development of pipeline infrastructure, which may impact our ability to transport our products. Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Hazardous Substances and Waste Management. RCRA and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, individual state governments administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil, natural gas, and drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.

CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a 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 addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials during our operations that may be regulated as hazardous substances. Despite the “petroleum exclusion” of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless generate or handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste 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, including off-site locations, where such substances have been taken for disposal. Under such laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of contaminated property, or remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.

Endangered Species Act. The federal Endangered Species Act (ESA) and analogous state laws regulate many activities, including oil and gas development, which could have an adverse effect on species listed as threatened or endangered under the ESA or their habitats. Designating previously unidentified endangered or threatened species could cause oil and natural gas exploration and production operators and service companies to incur additional costs or become subject to operating delays, restrictions or bans in affected areas, which impacts could adversely reduce drilling activities in affected areas. All three of our business segments could be subject to the effect of one or more species being listed as threatened or endangered within the areas of our operations. Numerous species have been listed or are under consideration for protected status under the ESA in areas in which we provide or could undertake operations, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse. In addition, the Supreme Court held in 2018 that only the actual habitat of an endangered species can be designated critical habitat, meaning that an uninhabited area that otherwise meets the definition of critical habitat should not be so designated. Following this decision, the U.S. Fish and Wildlife Service (FWS) and the National Marine Fisheries Service NMFS) issued joint regulations in December 2020 defining critical habitat to mean an area that currently or periodically contains the resources and conditions necessary to support a species listed under the ESA. The Department of Interior (DOI) also finalized rules in January 2021 under the Migratory Bird Treaty Act, which imposes similar restrictions and penalties as those found under the ESA, that limit the imposition of criminal sanctions in instances where only an incidental take of protected birds occurs. The Biden Administration has stated that it plans to review the FWS, NMFS, and DOI regulations and has paused implementation of the DOI rules.The presence of protected species in areas where we provide contract drilling or mid-stream services or conduct exploration and production operations could impair our ability to timely complete or carry out those services and, consequently, hurt our results of operations and financial position.

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Air Emissions. The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The EPA has also adopted rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. The EPA expanded on its emission standards for volatile organic compounds in June 2016 with the issuance of first-time standards, known as Subpart OOOOa, to address emissions of methane from equipment and processes across oil and natural gas production, storage, processing and transmission sources, including hydraulically fractured oil natural gas and well completions.

In September 2020, the Trump Administration finalized regulations that removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane specific requirements of OOOOa across all sources. These changes are currently subject to litigation, and Congress is considering repealing the September 2020 revisions pursuant to the Congressional Review Act. In addition, in January 2021, President Biden signed an executive order calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities. As a result, more stringent regulation of methane emissions from the oil and natural gas industry is expected.

Several states, including Colorado, Pennsylvania, New Mexico and Wyoming, have separately imposed their own regulations on methane emissions from the oil and natural gas sector. These regulations cover a variety of upstream and midstream sources and typically limit the venting and flaring of gas, require the installation of certain types of low-emitting equipment, and impose leak inspection and repair requirements. These and other air pollution control and permitting requirements have the potential to delay the development of oil and natural gas projects, increase our costs of development and operations, and increase costs for well decommissioning and abandonment.

Climate Change. Climate change continues to attract considerable public and scientific attention. As a result, our operations as well as the operations of our operators are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of greenhouse gases (GHGs). At the federal level, no comprehensive climate change law or regulation has been implemented to date. The EPA has, however, adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in recent years. For more information, see our regulatory disclosure titled “Air Emissions.”

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by the recently elected administration. These have included promises to limit emissions and curtail the production of oil and gas on federal lands, such as through the cessation of leasing public land for hydrocarbon development. For example, in January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors. Additionally, President Biden has signed executive orders recommitting the United States to the Paris Agreement, which requires member nations to submit non-binding, individually determined GHG emission reduction goals every five years after 2020. The impacts of these orders and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement remain unclear at this time. There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

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The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards upon GHG emissions from the oil and natural gas sector could result in increased costs of compliance. Concerns related to the impacts of climate change could also result in reduced demand for oil and natural gas and adversely impact the value of reserves. In addition, increased financial scrutiny of climate risks could result in restrictions on our access to capital. Moreover, there are increasing risks to operations resulting from the potential physical impacts of climate change, such as drought, wildfires, damage to infrastructure and resources from flooding, storms, and other natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Hydraulic Fracturing. Our oil and natural gas segment routinely apply hydraulic fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the Marmaton of Oklahoma, the Wilcox of Texas, and the Mississippian of Kansas. Hydraulic fracturing has been the subject of public scrutiny over the past several years. While states typically have primary authority with respect to regulating oil and natural gas production activities, including hydraulic fracturing, from time to time Congress has considered passing new laws to regulate this practice, and the U.S. Government has asserted regulatory authority over certain aspects of hydraulic fracturing. For example, the EPA finalized rules under the Clean Water Act in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Most recently, on March 23, 2021 the Fracturing Responsibility and Awareness of Chemicals Act was reintroduced in Congress, which includes resolutions that would authorize the EPA to regulate unconventional drilling activities, including requiring the disclosure of chemicals used, and end various exemptions for hydraulic fracturing in federal laws such as RCRA, the Safe Drinking Water Act, and the federal Clean Air Act. In addition, certain states in which we operate, including Texas, Oklahoma, Kansas, Colorado, and Wyoming have adopted, and other states and municipalities and other local governmental entities in some states, have and others are considering adopting regulations and ordinances that could impose more stringent permitting, require the public disclosure of chemicals in fracking fluids, flaring limitations, waste disposal, and well construction requirements on these operations, and even restrict or ban hydraulic fracturing in certain circumstances.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. Both the EPA and the United States Geological Survey (USGS) have made statements indicating that the disposal of wastes associated with hydraulic fracturing via injection wells may result in induced seismic events. Several states, including Texas, Oklahoma, and Kansas, have adopted measures limiting disposal well operations in areas under certain circumstances.

At the state level, several states, including Texas, have adopted or are considering legal requirements that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. Local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.Any new laws, regulation, or permitting requirements regarding hydraulic fracturing could lead to operational delay, or increased operating costs or third party or governmental claims, and could result in additional burdens that could delay or limit the drilling services we provide to third parties whose drilling operations could be affected by these regulations or increase our costs of compliance and doing business and delay the development of unconventional gas resources from shale formations which are not commercial without using hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the oil and natural gas we can ultimately produce from our reserves.

Other; Compliance Costs. We cannot predict future legislation or regulations. It is possible that some future laws, regulations, and/or ordinances could increase our compliance costs and/or impose additional operating restrictions on us as well as those of our customers. Such future developments also might curtail the demand for fossil fuels which could hurt the demand for our services, which could hurt our future results of operations. Likewise, we cannot predict with any certainty whether any changes to temperature, storm intensity or precipitation patterns because of climate change (or otherwise) will have a material impact on our operations.

Compliance with applicable environmental requirements has not, to date, had a material effect on the cost of our operations, earnings, or competitive position. However, as noted above in our discussion of the regulation of GHG and hydraulic fracturing, compliance with amended, new, or more stringent requirements of existing environmental regulations or requirements may cause us to incur additional costs or subject us to liabilities that may have a material adverse effect on our results of operations and financial condition.

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Item 1A. Risk Factors

RISK FACTORS

RISKS CONCERNING COMMODITY PRICES

Our business is heavily affected by commodity prices. Oil, NGLs, and natural gas prices are volatile, and low prices have hurt our financial results and could do so in the future.

Our revenues, operating results, cash flow, and growth depend on prevailing prices for oil, NGLs, and natural gas. Oil, NGLs, and natural gas prices and markets have been volatile, and they are likely to remain volatile.

The prices we receive for our oil, NGLs, and natural gas production affect our revenues, profitability, cash flow, and ability to meet our projected financial and operational goals. Prices also tend to influence third parties use of our services. Those prices are decided by many factors beyond our control, including:

•the demand for and supply of oil, NGLs, and natural gas;

•weather conditions in the continental United States (which can influence the demand and prices for natural gas);

•the amount and timing of oil, natural gas, and liquefied petroleum gas imports and exports;

•the ability of distribution systems in the United States to effectively meet the demand for oil, NGLs, and natural gas, particularly in times of peak demand which may result because of adverse weather conditions;

•the ability or willingness of OPEC to set and support production levels for oil;

•oil and gas production levels by non-OPEC countries;

•political and economic uncertainty and geopolitical activity, such as the current conflict occurring between Russia and Ukraine;

•governmental policies and subsidies;

•the costs of exploring for, producing, and delivering oil and natural gas;

•technological advances affecting energy consumption;

•United States storage levels of oil, NGLs, and natural gas;

•price, availability, and acceptance of alternative fuels;

•volatility in ethane prices causing rejection of ethane as part of the liquids processed stream;

•pandemics, epidemics, outbreaks, or other public health events, such as COVID-19; and

•worldwide economic conditions.

Oil prices are sensitive to domestic and foreign influences based on political, social, or economic underpinnings, any of which could have an immediate and significant effect on the price and supply of oil. Prices of oil, NGLs, and natural gas can also be influenced by trading on the commodities markets which has increased the volatility associated with these prices, causing large differences in prices on even a weekly and monthly basis.

Based on our production for the year ended December 31, 2021, a $0.10 per Mcf change in what we receive for our natural gas production, without the effect of derivatives, would cause a corresponding $250 per month ($3.0 million annualized) change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of derivatives, would result in a $130 per month ($1.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs price, without the effect of derivatives, would result in a $220 per month ($2.6 million annualized) change in our pre-tax operating cash flow.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of oil, NGLs, and natural gas.

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Our derivative arrangements might limit the benefit of increases in oil, NGLs, and/or natural gas prices.

To reduce our exposure to short-term fluctuations in the price of oil, NGLs, and natural gas, we may use derivative contracts like swaps and collars. To date, we have derivatives covering part, but not all of our production, which provides price protection only against declines in market prices on the production covered by those derivatives, but not otherwise. Should market prices for the production we have derivatives on exceed the prices due under our derivative contracts, our derivative contracts expose us to the risk of financial loss and limit the benefit to us of those increases in market prices. Volumes not covered by derivative contracts are subject to market prices. The Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this report in Item 7 has a more thorough discussion of our derivative arrangements.

If one or more of our counterparties are unable or unwilling to pay us under our commodity derivative contracts, it could have a material adverse effect on our financial condition and operating results.

If oil, NGLs, and natural gas prices decrease or are unusually volatile, we may have to take write-downs of our oil and natural gas properties, the carrying value of our drilling rigs, or our natural gas gathering and processing systems.

Each quarter we review the carrying value of our oil and natural gas properties under the SEC’s full cost accounting rules. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10% per year. Application of the ceiling test generally requires pricing future revenue at the unweighted arithmetic average of the price on the first day of the month for each month within the 12 months before the end of the reporting period (unless contractual arrangements define the prices) and requires a write-down for accounting purposes if the ceiling is exceeded. We may have to write-down the carrying value of our oil and natural gas properties when oil, NGLs, and natural gas prices are depressed. A write-down, if required, would cause a charge to earnings but would not impact cash flow from operating activities. Once incurred, a write-down is not reversible. Because our ceiling tests use a rolling 12-month look back average price, it is possible that a write-down during a reporting period will not remove the need for us to take future write-downs. This could occur when months with higher commodity prices roll off the 12 months and are replaced with more recent months having lower commodity prices.

Our drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost. We must periodically test to see if these values have been impaired whenever events or changes in circumstances suggest the carrying amount may not be recoverable. If these assets are determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of the property, equipment, and related intangible assets. Once these values are reduced, they are not reversible.

RISKS RELATED TO OIL, NGL, AND NATURAL GAS RESERVES

Many uncertainties are inherent in estimating quantities of oil, NGLs, and natural gas reserves and their values, including factors beyond our control. Actual production, revenues, and expenditures regarding our oil, NGLs, and natural gas reserves will likely vary from estimates, and those variances may be material.

Many uncertainties are inherent in estimating quantities of oil, NGLs, and natural gas reserves and their values, including factors beyond our control. The oil, NGLs, and natural gas reserve information in this report is only an estimate of these reserves. Oil, NGLs, and natural gas reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil, NGLs, and natural gas that cannot be measured precisely. Estimates of economically recoverable oil, NGLs, and natural gas reserves depend on several variable factors, including historical production from the area compared with production from other producing areas, and assumptions about: reservoir size; the effects of regulations by governmental agencies; future oil, NGLs, and natural gas prices; future operating costs; severance and excise taxes; operational risks; development costs; and workover and remedial costs.

Some or all these assumptions may vary considerably from actual results. For these and other reasons, estimates of the economically recoverable quantities of oil, NGLs, and natural gas attributable to any group of properties, classifications of those oil, NGLs, and natural gas reserves based on the risk of recovery, and estimates of the future net cash flows from oil, NGLs, and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Oil, NGLs, and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual production, revenues, and expenditures regarding our oil, NGLs, and natural gas reserves will likely vary from estimates, and those variances may be material.

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The information about discounted future net cash flows in this report is not necessarily the current market value of the estimated oil, NGLs, and natural gas reserves attributable to our properties. Using full cost accounting requires us to use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues unless prices were otherwise determined under contractual arrangements. Actual future prices and costs may be materially higher or lower. Actual future net cash flows are also affected by these factors:

•the amount and timing of oil, NGLs, and natural gas production;

•supply and demand for oil, NGLs, and natural gas;

•increases or decreases in consumption; and

•changes in governmental regulations or taxation.

What’s more, the 10% discount factor, required by the SEC for calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and the risks associated with our operations or the oil and natural gas industry.

Estimated quantities of oil, NGLs, and natural gas reserves and their values used to prepare our consolidated financial statements and supplemental oil and gas disclosures may differ from estimates used in other strategic or economic purposes.

As described above, the information about discounted future net cash flows in this report is not necessarily the current market value of the estimated oil, NGLs, and natural gas reserves attributable to our properties so estimates used by management for strategic or economic purposes may differ.

RISKS RELATED TO FINANCING OUR BUSINESS

Our inability to satisfy our debt obligations and covenants could result in our failure to meet our capital needs and adversely affect our operations.

We may incur substantial capital expenditures in our operations. Historically, we have funded our capital needs through a combination of internally generated cash flow and borrowings under our bank credit agreements. We have, and may continue to have, some indebtedness. As of December 31, 2021, we had no outstanding borrowings under the Exit credit agreement and $19.2 million of borrowings outstanding under the Superior credit agreement (as defined below).

Depending on our debt, the cash flow needed to satisfy that debt and the covenants in our bank credit agreements could:

•limit funds otherwise available for financing our capital expenditures, our drilling program, or other activities or cause us to curtail these activities;

•limit our flexibility in planning for or reacting to changes in our business;

•place us at a competitive disadvantage to those of our competitors less indebted than we are;

•make us more vulnerable during periods of low oil, NGLs, and natural gas prices or if a downturn in our business occurs; and

•prevent us from obtaining more financing on acceptable terms or limit amounts available under our existing or future credit facilities.

Our ability to meet our debt obligations depends on our future performance. If such obligations are not satisfied, a default could be deemed to occur, and our lenders could accelerate the payment of the outstanding indebtedness. If that were to happen, we would not have sufficient funds available (and probably could not obtain the financing required) to meet our obligations. See “Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict” below.

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Our existing debt and our future debt are based mainly on the costs of the projects we undertake and our cash flow. Generally, our expected operating costs are those resulting from the drilling of oil and natural gas wells, acquiring producing properties, the costs associated with the maintenance, upgrade, or expansion of our drilling rig fleet, and the operations of our natural gas buying, selling, gathering, processing, and treating systems. To some extent, these costs, mainly the first two, are discretionary, and we maintain some control on the timing or the need to incur them. Sometimes, unforeseen circumstances may arise, like an unexpected chance to make a large acquisition or the need to replace a costly drilling rig component due to an unexpected loss, which could force us to incur more debt above what we had expected or forecasted. Likewise, if our cash flow should prove insufficient to cover our cash requirements, we would need to increase our debt either through bank borrowings or otherwise.

Restrictive covenants in our credit facilities may limit our financial and operating flexibility and our ability to pursue our business strategies.

As of December 31, 2021, we had no outstanding borrowings under our Exit credit agreement and $19.2 million outstanding under our Superior credit agreement. Our financing agreements permit us to incur more indebtedness and other obligations. We may also seek amendments or waivers from our existing lenders if we need to incur indebtedness above amounts permitted by our financing agreements.

Our credit facilities contain certain restrictions, which may have adverse effects on our business, financial condition, cash flows or results of operations, limiting our ability, among other things, to:

•incur additional indebtedness;

•incur additional liens;

•pay dividends or make other distributions;

•make investments, loans, or advances;

•sell or discount receivables;

•enter into mergers;

•sell properties;

•enter into or terminate swap agreements;

•enter into transactions with affiliates;

•maintain gas imbalances;

•enter into take-or-pay contracts or make other prepayments;

•enter into sale and leaseback agreements;

•amend our organizational documents; and

•make capital expenditures.

The credit facilities also require us to comply with certain financial maintenance covenants as discussed elsewhere in this report.

A breach of any of these restrictive covenants could cause a default. If a default occurs, the lenders under our credit facilities may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due. The lenders would also have the right in that case to terminate any commitments they have to provide more borrowings. If we cannot repay our indebtedness when due or declared due, the lenders may also proceed against the collateral pledged to secure the indebtedness. If the indebtedness was accelerated, our assets might not fully repay our secured indebtedness.

Under the Exit credit agreement, the borrowing base is determined semi-annually at the lenders’ discretion and is based largely on the prices for oil, NGLs, and natural gas.

Significant declines in oil, NGLs, and natural gas prices may cause a decrease in our borrowing base. The lenders can unilaterally adjust the borrowing base, and therefore the borrowings permitted to be outstanding under the Exit credit agreement. If outstanding borrowings are over the borrowing base, we must (a) repay the amount over the borrowing base, (b) dedicate additional properties to the borrowing base, or (c) begin monthly principal payments.

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The amount Superior can borrow under its credit agreement may be affected by its cash flow.

Superior must maintain a funded debt to consolidated EBITDA ratio (as defined in the Superior credit agreement) of not greater than 4.00 to 1.00. If Superior’s EBITDA falls below $50.0 million, its maximum funded debt would be limited to 4.00 times consolidated EBITDA.

Disruptions in the financial markets could affect our ability to obtain financing or refinance existing indebtedness on reasonable terms and may have other adverse effects.

Commercial-credit and equity market disruptions may cause tight capital markets in the United States. Liquidity in the global capital markets can be severely contracted by market disruptions making financing less attractive. In some cases, it leads to the unavailability of certain types of financing. Because of credit and equity market turmoil, we may not obtain debt or equity financing or refinance existing indebtedness on favorable terms, which could affect operations and financial performance.

Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may hurt our indebtedness.

Our variable rate debt under both the Exit credit agreement and the Superior credit agreement is tied to LIBOR. On July 27, 2017, the Financial Conduct Authority announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established so that it continues to exist after 2021. There is no guarantee that a transition from LIBOR to an alternative will not cause financial market disruptions, significant increases in benchmark rates, or borrowing costs to borrowers, any of which could hurt our business, financial condition, and operations results.

RISKS RELATED TO OPERATING OUR BUSINESS

Increasing attention to environmental, social and governance (ESG) matters may adversely impact our business.

Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to evaluate their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and to the diversion of their investment away from the fossil fuel industry to other industries which could have a negative impact on our stock price and our access to and costs of capital.

Public health events outside our control, including pandemics, epidemics, and infectious disease outbreaks, like the recent global outbreak of COVID-19, have materially hurt and may further materially hurt our business.

We face risks related to epidemics, pandemics, outbreaks, or other public health events outside our control and could disrupt our operations and hurt their financial condition. The outbreak of the COVID-19 virus has spread across the globe and affected financial markets and worldwide economic activity. It may continue to negatively impact our operations or our workforce’s health by rendering employees or contractors unable to work or unable to access our facilities for an indefinite period. The effects of COVID-19 and concerns about its global spread have, during certain periods, weakened the domestic and international demand for crude oil and natural gas, hurting crude oil prices and causing significant price volatility. As the duration and full impact from COVID-19 is difficult to predict, how much it may hurt our operating results, or the duration of any potential business disruption is unknown. Any potential impact will depend on future developments, and new information that may emerge about the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact are beyond our control. These potential impacts, while unknown, could hurt our operating results.

The industries in which we operate are highly competitive, and many of our competitors have resources more significant than we do.

The drilling industry in which we operate is generally very competitive. Most drilling contracts are awarded based on competitive bids, which may cause intense price competition. Some of our competitors in the contract drilling industry have greater financial and human resources than we do. These resources may enable them to withstand periods of low drilling rig use better, compete more effectively based on price and technology, build new drilling rigs, or acquire existing drilling rigs, and provide drilling rigs more quickly than we do in periods of high drilling rig use.

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The oil and natural gas industry is also highly competitive. We compete in property acquisitions and oil and natural gas exploration, development, production, and marketing with major oil companies, other independent oil and natural gas concerns, and individual producers and operators. Many of our competitors in the oil and natural gas industry have resources substantially greater than we do.

The mid-stream industry is also highly competitive. We compete in gathering, processing, transporting, and treating natural gas with other mid-stream companies. We are continually competing with larger mid-stream companies for acquisitions and construction projects. Many of our competitors have greater financial resources, human resources, and geographic presence larger than we do.

Competition for experienced technical personnel may hurt our operations or financial results.

Our three segments’ success and the success of our other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, drilling rig hands, and other employees. Competition for these employees can be intense, particularly when the industry is experiencing favorable conditions.

Our operations are subject to inherent risks that, if material, could harm our results of operations.

Our contract drilling operations are subject to many hazards, including blowouts, cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment, and damage or loss from inclement weather. Our exploration and production and mid-stream operations are subject to these and similar risks. These events could cause personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage, and damage to others’ property. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer. We seek to obtain contractual indemnification from our drilling customers for some of these risks. If we cannot transfer these risks to drilling customers by contract or indemnification agreements (or if we assume obligations of indemnity or assume liability for certain risks under our drilling contracts), we seek protection from some of these risks through insurance. Still, some risks are not covered by insurance. We cannot assure you that the insurance we have or the indemnification agreements we have will adequately protect us against liability from the consequences of the hazards described above. An event not fully insured or indemnified against, or a customer’s failure to meet its indemnification obligations, could cause substantial losses. We cannot assure you that insurance will be available to cover any or all of these risks. Even if available, the insurance might not be adequate to cover all of our losses, or we might decide against obtaining that insurance because of high premiums or other costs.

Our exploration and development operations involve many risks that may cause dry holes, the failure to produce oil, NGLs, and natural gas in commercial quantities, and the inability to fully produce discovered reserves. The cost of drilling, completing, and operating wells is substantial and uncertain. Many of these factors are beyond our control and may cause the curtailment, delay, or cancellation of drilling operations.

Exploratory drilling is a speculative activity. Although we may disclose our overall drilling success rate, those rates may decline. Although we may discuss drilling prospects we have identified or budgeted for, we may ultimately not lease or drill these prospects within the expected period, or at all. Lack of drilling success will hurt our future results of operations and financial condition. We do not operate many wells in which we own an interest. Our operational risks for those wells and our ability to influence those wells’ operations are less subject to our control and the operators of those wells may act in ways not in our best interests.

Our oil and natural gas segment’s prospective drilling locations are in various evaluation stages, ranging from a prospect ready to drill to a prospect that will require additional geological and engineering analysis. Based on many factors, including future oil, NGLs, natural gas prices, the generation of additional seismic or geological information, and other factors, we may decide not to drill one or more of these prospects. We may not increase or maintain our reserves or production, which could hurt our business, financial position, and operating results. The SEC’s reserve reporting rules require that, subject to limited exceptions, proved undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of booking. At December 31, 2021, we had no proved undeveloped drilling locations.

Our mid-stream operations involve many risks, both financial and operational. The cost of developing gathering systems and processing plants is substantial, and our ability to recoup these costs is uncertain. Our operations may be curtailed, delayed, or canceled because of many things beyond our control, including:

•unexpected changes in the deliverability of natural gas reserves from the wells connected to the gathering systems;

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•availability of competing pipelines in the area;

•the capacity of pipeline systems;

•equipment failures or accidents;

•adverse weather conditions;

•compliance with governmental requirements;

•delays in developing other producing properties within the gathering system’s area of operation; and

•demand for natural gas and its constituents.

New technologies may cause our exploration and drilling methods to become obsolete, causing an adverse effect on our production.

Our industry is subject to rapid and significant technological advancements, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may allow them to implement new technologies before we can. We cannot be sure that we can implement technologies timely or at an acceptable cost. One or more technologies we use or that we may implement may become obsolete or may not work as we expected, and we may be hurt financially and operationally as a result.

Our operating results depend on our ability to transport oil, NGLs, and gas production to key markets.

The marketability of our oil, NGLs, and natural gas production depends in part on the availability, proximity, and capacity of pipeline systems, refineries, and other transportation sources. The unavailability of or lack of capacity on these systems and facilities could cause the shut-in of producing wells or the delay or discontinuance of development plans for properties. Federal and state regulation of oil, NGLs, and natural gas production and transportation, tax, and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, and general economic conditions could hurt our ability to produce, gather, and, transport oil, NGLs, and natural gas.

Losing one or several of our larger customers could have a material adverse effect on our financial condition and results of operations.

During the year ended December 31, 2021, one customer accounted for 11% of our oil and natural gas revenue, five customers accounted for 79% of our contract drilling revenues, and three customers accounted for 58% of our Mid-Stream revenues. No other third-party customer accounted for 10% or more of any of our segment revenues. Any customer may choose not to use our services or purchase oil, natural gas, or NGLS from us, and losing one or several of our larger customers could have a material adverse effect on our financial condition and results of operations if we could not find replacements.

Superior depends on certain natural gas producers and pipeline operators for a significant portion of its supply of natural gas and NGLs. Losing any of these producers could cause a decline in our volumes and revenues.

We rely on certain natural gas producers for a significant portion of our natural gas and NGLs supply. While some of these producers are subject to long-term contracts, we may not negotiate extensions or replacements of these contracts on favorable terms, if at all. Losing all or even a portion of the natural gas volumes supplied by these producers, because of competition or otherwise, could have a material adverse effect on our mid-stream segment unless we acquired comparable volumes from other sources.

We rely on management and other key employees.

We depend significantly on the efforts of our executive officers and other key employees to manage our operations. The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.

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We are subject to various claims and litigation that could ultimately be resolved against us, requiring material future cash payments or future material charges against our operating income, and materially impairing our financial position.

The nature of our business makes us highly susceptible to claims and litigation. We are subject to various existing legal claims and lawsuits, which could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. Even if indemnified or insured, any claims or litigation could hurt our reputation among our customers and the public and make it harder for us to compete effectively or obtain adequate insurance in the future.

Demand for our contract drilling and mid-stream services depends on the levels of spending by the oil and gas industry. A substantial or an extended decline in oil and gas prices could cause lower spending by the oil and gas industry, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

Demand for our contract drilling and mid-stream services depends on the oil and gas industry’s level of expenditures for the exploration, development, and production of oil and natural gas reserves. These expenditures generally depend on the industry’s view of future oil and natural gas prices and are sensitive to the industry’s view of future economic growth and the resulting effect on demand for oil and natural gas. Declines and anticipated declines in oil and gas prices could also cause project modifications, delays, or cancellations, general business disruptions, and delays in payment of, or nonpayment of, amounts owed to us. These effects could have a material adverse effect on our financial condition, results of operations, and cash flows.

Climate change legislation or other regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil, natural gas and NGL we produce.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and may continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, mandates for the production of renewable fuels, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in recent years. For more information, see our regulatory disclosure titled “Air Emissions.”

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Geopolitical tensions from the conflict between Russia and Ukraine may create market volatility or other disruptions which could negatively impact our ability to carry out our business plan.

Although we have no direct transactional or supply chain exposure to the areas of conflict, the current conflict between Russia and Ukraine, and related geopolitical and economic responses, could significantly impact the global financial markets and supply chains, or cause other disruptions which could negatively impact our business plan and operations.

RISKS TO OUR POTENTIAL GROWTH PLANS

Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict.

Any growth plans may require significant cash. Our principal sources of liquidity include the available borrowing capacity under the Exit credit agreement and cash flow generated from operations. If our cash flow from operations decreases, we may be unable to expend the capital to maintain our operations, hurting our future revenues. Our liquidity, including our ability to meet our ongoing operational obligations, depends on, among other things: (i) our ability to comply with the terms of the Exit credit agreement, (ii) our ability to maintain adequate cash on hand, and (iii) our ability to generate cash flow from operations.

Growth through acquisitions is not assured.

We have historically grown through mergers and acquisitions. The contract land drilling industry, the exploration and development industry, and the gas gathering and processing industry have experienced significant consolidation over the past several years. There is no assurance that acquisition opportunities will be available or viable. Even if available, there is no assurance we would have the financial ability to pursue the opportunity. We expect the competition for acquisition opportunities to persist or intensify.

We may incur substantial indebtedness to finance future acquisitions and may issue debt instruments, equity securities, or convertible securities in connection with any acquisitions. Debt service requirements could represent a significant burden on our operations and financial condition and issuing more equity would be dilutive to existing shareholders. In addition, continued growth could strain our management, operations, employees, and other resources.

Successful acquisitions, particularly those of oil and natural gas companies or oil and natural gas properties, require assessing several factors, many of which are beyond our control. These factors include recoverable reserves, exploration potential, future oil, NGLs, and natural gas prices, operating costs, and potential environmental and other liabilities. Such assessments are inexact, and their accuracy is inherently uncertain.

Our future performance may depend on our ability to find or acquire more oil, NGLs, and natural gas reserves that are economically recoverable.

Production from oil and natural gas properties declines as reserves are depleted, with a well's decline rate depending on reservoir characteristics. Unless we replace the reserves, we produce, our reserves will decline, resulting in a decrease in oil, NGLs, and natural gas production and lower revenues and cash flow. Historically, we have increased reserves after considering our production through exploration and development. We have conducted these activities on our existing oil and natural gas properties and newly acquired properties. We may not be able to continue to replace reserves from these activities at acceptable costs. Lower prices for oil, NGLs, and natural gas may further limit the reserves that can economically be developed. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.

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If we are to construct new proprietary BOSS drilling rigs, the process would be subject to risks, including delays and cost overruns, and rigs that may not meet our expectations.

We have designed and built several proprietary 1,500 horsepower AC electric drilling rigs called BOSS drilling rigs. This new design should position us to meet the demands of our customers better. Constructing any future new BOSS drilling rigs is subject to the risks of delays or cost overruns in any large construction project because of many possible factors.

BOSS drilling rig designs may be subject to intellectual property rights claims.

While we hold certain patents on our BOSS drilling rig design, it is still possible that third parties may claim that our BOSS drilling rig design infringes on their intellectual property rights. In that event, we may resolve these claims by signing royalty and licensing agreements, redesigning the drilling rig, or paying damages. These outcomes may cause operating margins to decline. In addition to money damages, plaintiffs may seek injunctive relief in some jurisdictions that may limit or prevent marketing and use of our drilling rigs if they are determined to be an infringement upon a third party's intellectual property rights.

RISKS RELATED TO REGULATIONS

New laws, policies, regulations, rulemaking, and oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows, and operations.

Our business is subject to federal, state, and local laws and regulations on taxation, the exploration for and development, production, and marketing of oil and natural gas, and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, production rates, prevention of waste, unitization and pooling of properties, and other matters. These laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning our oil and natural gas wells and other facilities. These laws and regulations, and any others passed by the jurisdictions where we have production, could limit the number of wells drilled or the allowable production from successful wells, limiting our revenues.

We are (or could become) subject to complex environmental laws and regulations adopted by the jurisdictions where we own properties or operate. We could incur liability to governments or third parties for discharges of oil, natural gas, or other pollutants into the air, soil, or water, including responsibility for remedial costs. We could discharge these materials into the environment in many ways, including:

•from a well or drilling equipment at a drill site;

•from gathering systems, pipelines, transportation facilities, and storage tanks;

•damage to oil and natural gas wells resulting from accidents during normal operations;

•sabotage; and

•blowouts, cratering, and explosions.

Because the requirements imposed by laws and regulations often change, we cannot assure you that future laws and regulations, including changes to existing laws and regulations, will not have a material adverse effect on our business or results of operations. The United States Congress and White House administration may impose more stringent environmental requirements on our operations or change existing laws and regulations in a manner that could adversely impact our business. Stricter standards, greater regulation, and more extensive permit requirements could increase our future risks and costs related to environmental matters. Because we acquire interests in properties operated in the past by others, we may be liable for environmental damage caused by the former operators, which liability could be material.

We could be subject to increased compliance costs related to the regulation of our pipelines.

Our pipelines are also subject to regulation by the Department of Transportation (DOT) under the Natural Gas Pipeline Safety Act of 1968, as amended, Hazardous Liquid Pipeline Safety Act of 1979, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act). The federal Pipeline and Hazardous Materials Safety Administration (PHMSA) implements these statutes. Recently, PHMSA has taken several steps to expand its jurisdiction over crude oil and natural gas pipelines, including gathering lines.

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PHMSA issued three separate final rulemakings in 2019 that significantly expand the regulation of natural gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, and maximum allowable operating pressure limits, among others. PHMSA has also finalized rules for hazardous liquids pipelines that expand existing pipeline integrity management requirements. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events, natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to interfere with our production, increase our cost and damage infrastructure.

On August 3, 2020, the United States Senate reauthorized the Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act to reauthorize pipeline safety programs through fiscal year 2023. The PIPES Act contains provisions for methane leak detection, monitoring, and repair, the maintenance of emergency response plans, and other pipeline safety regulations. Therefore, additional future regulatory action expanding PHMSA’s jurisdiction and imposing stricter integrity management requirements is possible. The adoption of laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operating costs that could be significant. In addition, should we fail to comply with PHMSA or comparable state regulations, we could be subject to substantial fines and penalties. Effective January 11, 2021, the maximum civil penalties PHMSA can impose are $222,504 per violation per day, with a maximum of $2,225,034 for a related series of violations.

Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate the production of oil, natural gas, and associated liquids from dense subsurface rock formations. Our oil and natural gas segment routinely applies hydraulic-fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the Marmaton and Hoxbar of Oklahoma, the Wilcox of Texas. Hydraulic-fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow hydrocarbons’ flow into the wellbore. State oil and natural gas commissions process typically regulate this process, but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and published permitting guidance addressing the performance of such activities. The EPA has also finalized rules under the Clean Water Act in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Separately, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.

Some states where we operate, including Texas, Oklahoma, Kansas, Colorado, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure of fracking fluids, waste disposal, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Local governments may also seek to restrict or prohibit well-drilling, hydraulic fracturing, or both. If state, local, or municipal legal restrictions are adopted in areas where we are conducting or plan to conduct operations, we may incur added costs to comply with such requirements that may be significant, experience delays or curtailment pursuing exploration, development, or production activities, and perhaps even be precluded from the drilling and completion of wells.

In addition, our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired if we cannot get adequate supplies of water for our drilling and completion operations or cannot dispose of or recycle the water we use at a reasonable cost and under applicable environmental rules. Any new laws, regulation, or permitting requirements regarding hydraulic fracturing could lead to operational delays, or increased operating costs or third party or governmental claims, and could result in additional burdens that could delay or limit the drilling services we provide to third parties whose drilling operations could be affected by these regulations or increase our costs of compliance and doing business and delay the development of unconventional gas resources from shale formations which are not commercial without using hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the oil and natural gas we can ultimately produce from our reserves.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect intended to supply coverage for losses solely related to hydraulic fracturing operations, but our general liability and excess liability insurance policies might cover third-party claims related to hydraulic fracturing operations and associated legal expenses depending on the specific nature of the claims, the timing of the claims, and the specific terms of such policies.

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Uncertainty about increased seismic activity in Oklahoma could have adverse effect on our business and results of operations.

We conduct oil and natural gas exploration, development, and drilling activities in Oklahoma and nearby. In recent years, Oklahoma, Texas, and Kansas have experienced an upturn in earthquakes and other seismic activity. Some parties believe there is a correlation between certain oil and gas activities and earthquakes’ increased occurrence. The extent of this correlation is the subject of studies by both state and federal agencies, the results of which remain unclear. We cannot say what impact this seismic activity may have on us or our industry.

The hydraulic fracturing process on which we depend to produce commercial quantities of crude oil, natural gas, and associated NGLs from many reservoirs requires the use and disposal of significant water quantities.

Our inability to secure enough water or dispose of or recycle the water used in our oil and natural gas segment operations could hurt our operations. Imposing new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of oil and natural gas.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage and, use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could hurt our operations and financial condition.

The potential listing of species as “endangered” under the federal Endangered Species Act could cause increased costs and new operating restrictions or delays on our operations and of our customers, which could hurt our operations and financial results.

The ESA and similar state laws regulate various activities, including oil and gas development, which could harm species listed as threatened or endangered under the ESA or their habitats. Designating previously unidentified endangered or threatened species could cause oil and natural gas exploration and production operators and service companies to incur added costs or become subject to operating delays, restrictions, or bans in affected areas, which impacts could reduce drilling activities in affected areas. All three of our business segments could be subject to the effect of one or more species being listed as threatened or endangered within the areas of our operations. Many species have been listed or are under consideration for protected status in areas we operate or could undertake operations, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse.

Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition, or results of operations.

Terrorist attacks or cyber-attacks may affect the energy industry and economic conditions, including our operations and our customers, general economic conditions, consumer confidence and spending, and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other United States targets. A cyber incident could cause information theft, data corruption, operational disruption, and financial loss. Our insurance may not protect us against such occurrences. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, and results of operations.

We are increasingly dependent on digital technologies, including information systems, infrastructure, and cloud applications and services, to operate our businesses, process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of natural gas reserves, and perform other activities related to our businesses. Our business partners, including vendors, service providers, and financial institutions, also depend on digital technology.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems to misappropriate assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites.

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Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could cause the unauthorized release, gathering, monitoring, misuse, loss, or destruction of proprietary and other information, or other disruption of our business operations. Some cyber incidents, like surveillance, may remain undetected for a long time.

Deliberate attacks on our assets, or security breaches in our systems or infrastructure, the systems or infrastructure of third-parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions, and third-party liability, including:

•a cyber-attack on a vendor or service provider could cause supply chain disruptions, which could delay or halt the development of more infrastructure, effectively delaying the start of cash flows from the project;

•a cyber-attack on our facilities may cause equipment damage or failure;

•a cyber-attack on mid-stream or downstream pipelines could prevent our products from being delivered, leading to losing revenues;

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

•deliberate corruption of our financial or operational data could cause events of non-compliance leading to regulatory fines or penalties; and

•business interruptions could cause expensive remediation efforts, the distraction of management, or damage to our reputation.

Implementation of various controls and processes to monitor and mitigate security threats and increase security for our information, facilities and infrastructure are costly and labor-intensive. There can be no assurance that such measures will prevent security breaches from occurring. As cyber threats continue to evolve, we may have to spend significant additional resources to modify or enhance our protective measures or investigate and remediate any information security vulnerabilities.

Ineffective internal controls could affect the accuracy and timely reporting of our business and financial results.

Our internal control over financial reporting (ICFR) may not prevent or detect misstatements because of its inherent limitations, including the possibility of human error, the circumvention or overriding of controls, or fraud. Even effective internal controls can provide only reasonable assurance about the preparation and fair presentation of financial statements. If we do not maintain our internal controls’ adequacy, including any failure to implement needed new or improved controls, or if we experience difficulties in their implementation, our business and financial results could be harmed, and we could fail to meet our financial reporting obligations.

POST REORGANIZATION RISKS

Because our consolidated financial statements reflect fresh start accounting adjustments made on emergence from bankruptcy, financial information in our financial statements are not comparable to our financial information from prior periods.

With our emergence from bankruptcy on the Effective Date, we determined that the company qualified for fresh start accounting under ASC Topic 852, Reorganizations, under which our reorganization value, which represents the fair value of the entity before considering liabilities, is distributed to the fair value of assets in conformity with the purchase method of accounting for business combinations. We state our liabilities, other than deferred taxes, at a present value of amounts expected to be paid. Thus, our consolidated balance sheets and consolidated statements of operations are not comparable in many respects to consolidated balance sheets and consolidated statements of operations data for periods before we adopted fresh start accounting. You cannot compare information reflecting our post-emergence financial statements to information for periods before we emerged from bankruptcy without adjusting for fresh start accounting.

Even though the Plan has been consummated, we may not achieve our stated goals.

Even though the Plan has been substantially consummated, we may continue to face several risks, such as further deterioration or other changes in economic conditions, changes in our industry, changes in demand for our services, and increasing expenses. We cannot guarantee that the Plan and subsequent performance will achieve our stated goals.

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Even though our debts were reduced through the Plan, we may need to raise additional funds through public or private debt or equity financing, or other various means to fund our business after completing the Chapter 11 Cases. Our access to additional financing may be limited, if available at all. Thus, adequate funds may not be available when needed or may not be available on favorable terms.

RISKS RELATED TO OWNERSHIP OF OUR CAPITAL STOCK

Holders of the New Common Stock and Warrants could be subject to U.S. federal withholding tax and/or U.S. federal income tax and corresponding tax reporting obligations on the sale, exchange, or other disposition of the New Common Stock and Warrants, which could adversely affect the trading and liquidity of the New Common Stock and Warrants.

The company believes that it is, and will remain for the foreseeable future, a “U.S. real property holding corporation” for U.S. federal income tax purposes. Under the Foreign Investment in Real Property Tax Act (FIRPTA), non-U.S. holders may be subject to U.S. federal income tax on the gain from the sale, exchange, or other disposition of shares of New Common Stock and Warrants, in which case they would also have to file U.S. federal income tax returns about that gain and may be subject to a U.S. federal withholding tax on a disposition of shares of New Common Stock and Warrants. Whether these FIRPTA provisions apply depends on the amount of New Common Stock or Warrants that the non-U.S. holders hold and whether, when they dispose of their New Common Stock or Warrants, the New Common Stock is treated as regularly traded on an established securities market under the Treasury Regulations (regularly traded).

If the New Common Stock is regularly traded during a calendar quarter, (A) no withholding requirements would be imposed under FIRPTA on transfers of New Common Stock or Warrants and (B) only a non-U.S. holder who has held, actually or constructively, (i) over 5% of New Common Stock or (ii) Warrants with a fair market value greater than 5% of the New Common Stock into which it is convertible, in each case at any time during the shorter of (x) the five years ending on the date of disposition, and (y) the non-U.S. holder’s holding period for its shares of New Common Stock or Warrants, would be subject to U.S. federal income tax on the sale, exchange, or disposition of such shares of New Common Stock or Warrants during such calendar quarter under FIRPTA.

If during any calendar quarter the New Common Stock is not regularly traded, any purchaser of New Common Stock or Warrants generally will have to withhold (and remit to the Internal Revenue Service (IRS)) 15% of the gross proceeds from the sale of the New Common Stock or Warrants unless provided with a certificate of non-foreign status or an IRS withholding certificate from the seller. Because the New Common Stock and Warrants were issued in book-entry form through DTC, sellers may not provide the necessary documentation to the purchasers to establish an exemption from withholding. Additionally, the purchasers may not withhold from the purchase price and remit the withheld amount to the IRS if they cannot obtain the sellers’ identifying information. It may be difficult or impossible to complete a transfer in compliance with tax laws in any calendar quarter when the New Common Stock is not regularly traded.

Our New Common Stock is currently quoted on the OTC Pink Marketplace and may be treated as regularly traded during any calendar quarter in which it is regularly quoted on one of the OTC markets by brokers or dealers making a market in the New Common Stock. But no assurances can be given that brokers or dealers will regularly quote the New Common Stock on such OTC market. If the New Common Stock is not regularly traded, the trading and liquidity of the New Common Stock and Warrants could be hurt because of the withholding and other tax obligations under FIRPTA.

Our New Common Stock may have a limited market and lack liquidity.

While our New Common Stock is being quoted on the OTC Pink marketplace, the OTC Pink marketplace is a more limited market than the NYSE or The Nasdaq Stock Market. The quotation of our shares on such a marketplace may cause a less liquid market available for existing and potential stockholders to trade shares of our New Common Stock, depress the trading price of our New Common Stock, and have a long-term adverse impact on our ability to raise capital. There can be no assurance there will be an active market for our shares of New Common Stock, either now or in the future, or that stockholders can liquidate their investment or liquidate it at a price that reflects the business’ value.

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Our charter and by-laws contain provisions that could delay or discourage a change in control transaction or prevent stockholders from receiving a premium on their investment.

Our charter and bylaws contain provisions that may delay or discourage change in control transactions or changes in our management or transactions that our stockholders might otherwise deem to be in their best interests or that might result in a premium over the market price for our shares, including, among other things:

•For so long as we do not have a class of securities registered under Section 12 of the Exchange Act, until the earlier to occur of (x) the Consenting Noteholders (as defined in the Plan) ceasing to hold at least 50% of the outstanding voting stock and (y) a public offering of common stock having occurred and shares of the company’s common stock with a value of at least $250.0 million having been listed for trading on a national securities exchange, the company cannot take certain actions without the consent of holders of at least 50% of the voting stock. Such actions include, among other things and subject to certain exceptions, (i) increasing or decreasing the size of the board, (ii) undertaking any fundamental change to the nature of the business, or (iii) consummating a public offering of common stock.

•The board is divided into two classes, Group I and Group II. The Group I directors initially served until the company’s 2023 annual meeting of stockholders, and the Group II directors will initially serve until the company’s 2022 annual meeting of stockholders. Each nominee for director will stand for election to a two-year term expiring at the second annual meeting of stockholders after that director’s election and until such director’s successor is duly elected and qualified, subject to that director’s earlier resignation, retirement, removal from office, death, or incapacity.

•Courts in Delaware are the exclusive forum for derivative actions and certain other actions and claims.

•To ensure the preservation of certain tax attributes to benefit the company and its stockholders, the charter contains certain restrictions on transfer of the company’s equity securities by persons with a percentage stock ownership of 4.75% or more.

•Special meetings of the stockholders may only be called by the board or by the secretary of the company at the request of stockholders owning at least 25% of the voting stock.

•The board has the ability to authorize undesignated preferred stock. This ability makes it possible for our board to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us.

•Vacancies on our board of directors and newly created directorships will be filled solely by the affirmative vote of a majority of directors then in office, even if less than a quorum, or by a sole remaining director.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The information called for by this item was consolidated with and disclosed in connection with Item 1 above.

Item 3. Legal Proceedings

For more information regarding legal proceedings, see Note 21 - Commitments And Contingencies of our Notes to Consolidated Financial Statements in Item 8 of this report.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

New Common Stock

After the Effective Date, we authorized 12.0 million shares of New Common Stock to be distributed under the Plan. The New Common Stock is not registered under Section 12 of the Exchange Act. On March 23, 2021, FINRA authorized a broker dealer to initiate a priced quotation of the New Common Stock on the OTC Pink Marketplace under the symbol "UNTC". See “Risk Factors — Our New Common Stock may have a limited market and lack liquidity” under Item 1A of this report.

Since all of our stockholders maintain their shares in “street name” accounts and are not, individually, stockholders of record, as of March 31, 2022, there was one holder of record of our common stock.

Allocation of New Common Stock

As contemplated by the Plan, the company distributed 10,527,507 and 683,038 shares of New Common Stock to holders of the subordinated notes claims on December 11, 2020 and July 26, 2021, respectively, as well as 161,328 and 3,055 shares of New Common Stock to holders of allowed general unsecured claims on October 20, 2021 and February 23, 2022, respectively, as a result of the pro rata distribution of shares of New Common Stock out of the equity reserves established under the Plan for certain disputed claims against the company and UPC. The shares of New Common Stock were distributed pursuant to Section 1145 of the Bankruptcy Code (which generally exempts from registration under the federal and state securities laws the issuance of securities in exchange for interests in or claims against a debtor under a plan of reorganization). Pursuant to the Plan, all shares of New Common Stock were distributed in book-entry form through the facilities of The Depository Trust Company (DTC).

Common Stock Dividends

We have declared no cash dividends on our common stock. Any future determination by our board of directors to pay dividends on our common stock will be made only after considering our financial condition, results of operations, capital requirements, and other relevant factors. Under certain circumstances, none of which applied as of December 31, 2021, our bank credit agreements may restrict the payment of cash dividends on our common stock. For further information regarding how our bank credit agreements may impact our ability to pay dividends, see “Credit Agreements” under Item 7 of this report.

Share Repurchases

In June 2021, we repurchased an aggregate of 600,000 shares of our common stock from the Lenders (as defined in Note 10 - Long-Term Debt And Other Long-Term Liabilities) which received these shares as an exit fee during our reorganization. The Lenders were paid $15.00 per share for their respective shares, for an aggregate cash purchase price of $9.0 million. The cash purchase price and direct acquisition costs are reflected as treasury stock on the consolidated balance sheets as of December 31, 2021.

In June 2021, our board of directors (the Board) authorized repurchasing up to $25.0 million of our outstanding common stock. In October 2021, the Board authorized an increase from $25.0 million of authorized repurchases to $50.0 million. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. We have no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice.

As of December 31, 2021, we had repurchased a total of 1,271,963 shares at an average share price of $32.57 for an aggregate purchase price of $41.4 million under the repurchase program.

During the year ended December 31, 2021, we also repurchased 78,000 shares in a privately negotiated transaction at a share price of $19.07 which were not part of the repurchase program.

The cumulative number of shares repurchased as of December 31, 2021 totaled 1,949,963, resulting in outstanding shares of 10,050,037.

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The table below represents all share repurchases for the three months ended December 31, 2021:


Period	Total number of shares purchased	Average price paid per share		Total number of shares purchased as part of publicly announced program	Approximate dollar value of shares that may yet be purchased under the program
					(in thousands)
October 1, 2021 through October 31, 2021	—	$	—	—	$	40,653
November 1, 2021 through November 30, 2021	861,926	$	34.80	861,926	$	10,658
December 1, 2021 through December 31, 2021	60,000	$	34.80	60,000	$	8,570

Item 6. [Reserved]

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Please read this discussion of our financial condition and results of operations with the consolidated financial statements and related notes in Item 8 of this report.

Introduction

We operate, manage, and analyze our results of operations through our three principal business segments:

•Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires, and produces oil and natural gas properties for our own account.

•Contract Drilling – carried out by our subsidiary Unit Drilling Company. This segment contracts to drill onshore oil and natural gas wells for others and for our own account.

•Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account. We own 50% of this subsidiary.

In our oil and natural gas segment, we are optimizing production and converting non-producing reserves to producing, with selective drilling activities in core areas. The company initiated an asset divestiture program at the beginning of 2021 to sell certain non-core oil and gas properties and reserves (the “Divestiture Program”). On October 4, 2021, the company announced that it is expanding the Divestiture Program to now include the potential sale of additional properties, including up to all of UPC’s oil and gas properties and reserves. On January 20, 2022, the company announced that it has retained a financial advisor and launched the process.

In our contract drilling segment, management reduced the number of drilling rigs available for use from 58 at December 31, 2020 to 21 during the second quarter of 2021 in order to focus on utilization of our BOSS drilling rigs and certain SCR rigs that are either currently under contract or candidates for future upgrades. Of the 21 rigs available for use, 14 are currently working, 3 are actively being marketed, and the remaining 4 will be considered for upgrade and marketing as future conditions warrant. We also plan to continue seeking opportunities to divest non-core, idle drilling equipment.

In our mid-stream segment, we are focused on continuing to generate predictable free cash flows with limited exposure to commodity prices. We also plan to continue seeking business development opportunities in our core areas utilizing the Superior credit agreement (which Unit is not a party to and does not guarantee) or other financing sources that are available to it.

Upon our emergence from the Chapter 11 Cases on September 3, 2020, we adopted fresh start accounting as required by US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, our consolidated financial statements after August 31, 2020 are not comparable with our consolidated financial statements prior to that date.

Recent Developments

Commodity Price Environment and COVID-19 Pandemic

Our success depends, among other things, on prices we receive for our oil and natural gas production, the demand for oil, natural gas, and NGLs, and the demand for our drilling rigs which influences the amounts we can charge for those drilling rigs. While our operations are all within the United States, events outside the United States affect us and our industry, including political and economic uncertainty and geopolitical activity.

We are continuously monitoring the current and potential impacts of the COVID-19 pandemic, including any new variants, on our business. This includes how it has and may continue to impact our operations, financial results, liquidity, customers, employees, and vendors as new COVID-19 variants may have undetermined impacts to our business. In response to the pandemic, we have implemented various measures to ensure we are conducting our business in a safe and secure manner.

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During the last two years commodity prices have been volatile, and the outlook for future oil and gas prices remains uncertain and subject to many factors. The following chart reflects the significant fluctuations in the historical prices for oil and natural gas:

The following chart reflects the significant fluctuations in the prices for NGLs(1):

_________________________

1.NGLs prices reflect a weighted-average, based on production, of Mont Belvieu and Conway prices.

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Stock Repurchase Activity

As of December 31, 2021, we had repurchased a total of 1,271,963 shares at an average share price of $32.57 for an aggregate purchase price of $41.4 million under the repurchase program.

During the year ended December 31, 2021, we also repurchased 78,000 shares in a privately negotiated transaction at a share price of $19.07 which were not part of the repurchase program.

The cumulative number of shares repurchased as of December 31, 2021 totaled 1,949,963, resulting in outstanding shares of 10,050,037.

Warrants

Each holder of the Old Common Stock outstanding before the Effective Date that did not opt out of the release under the Plan, is entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant will initially be exercisable for one share of New Common Stock, subject to adjustment as provided in the Warrant Agreement. The exercise price of the Warrants will be determined, and the Warrants will become exercisable, once the Debtors have completed the claims reconciliation process and resolved any objections to disputed claims under the Bankruptcy Petitions. The initial exercise price per share for the Warrants will be set at an amount that implies a recovery by holders of the Subordinated Notes of the $650 million principal amount of the Subordinated Notes plus interest thereon to the May 15, 2021 maturity date of the Notes. The Warrants expire on the earliest of (i) September 3, 2027, (ii) consummation of a Cash Sale (as defined in the Warrant Agreement) or (iii) the consummation of a liquidation, dissolutions or winding up of the company (such earliest date, the Expiration Date). Each Warrant that is not exercised on or before the Expiration Date will expire, and all rights under that Warrant and the Warrant Agreement will cease on the Expiration Date.

The warrants issued to holders of the company’s Old Common Stock that did not opt-out of the releases under the Plan and that owned their shares of old common stock through Direct Registration are outlined below:


Issuance Date			Warrants Issued
December 21, 2020			1,764,164
February 11, 2021			42,511
July 29, 2021			10,521
October 13, 2021			5,005
Total			1,822,201

The company expects to issue approximately 21,117 more Warrants to the holders of the Old Common Stock that did not opt-out of the releases under the Plan and owned their shares through Direct Registration.

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Superior MSA and LLC amendments

Critical Accounting Policies and Estimates

Summary

In this section, we identify those critical accounting policies we follow in preparing our financial statements and related disclosures. Many policies require us to make difficult, subjective, and complex judgments while making estimates of matters inherently imprecise. Some accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or had different assumptions been used. We evaluate our estimates and assumptions regularly. We base our estimates on historical experience and various other assumptions we believe are reasonable under the circumstances, the results of which support making judgments about the carrying values of assets and liabilities not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements.

Significant Estimates and Assumptions

Full Cost Method of Accounting for Oil, NGLs, and Natural Gas Properties. Determining our oil, NGLs, and natural gas reserves is a subjective process. It entails estimating underground accumulations of oil, NGLs, and natural gas that cannot be measured in an exact manner. Accuracy of these estimates depends on several factors, including, the quality and availability of geological and engineering data, the precision of the interpretations of that data, and individual judgments. Each year, we hire an independent petroleum engineering firm to audit our internal evaluation of our reserves. That audit as of December 31, 2021 covered those reserves we projected to comprise 85% of the total proved developed future net income discounted at 10% (based on the SEC's unescalated pricing policy). Included in Part I, Item 1 of this report are the qualifications of our independent petroleum engineering firm and our employees responsible for preparing our reserve reports.

The accuracy of estimating oil, NGLs, and natural gas reserves varies with the reserve classification and the related accumulation of available data, as shown in this table:

Type of Reserves

Nature of Available Data

Degree of Accuracy

Proved undeveloped

Data from offsetting wells, seismic data

Less accurate

Proved developed non-producing

The above and logs, core samples, well tests, pressure data

More accurate

Proved developed producing

The above and production history, pressure data over time

Most accurate

Assumptions of future oil, NGLs, and natural gas prices and operating and capital costs also play a significant role in estimating these reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are influenced by the assumed prices and costs due to the economic limit (that point when the projected costs and expenses of producing recoverable oil, NGLs, and natural gas reserves are greater than the projected revenues from the oil, NGLs, and natural gas reserves). But more significantly, the estimated present value of the future cash flows from our oil, NGLs, and natural gas reserves is sensitive to prices and costs and may vary materially based on different assumptions. We use full cost accounting which factors in the unweighted arithmetic average of the commodity prices existing on the first day of each of the twelve months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements.

We compute DD&A on a units-of-production method. Each quarter, we use these formulas to compute the provision for DD&A for our producing properties:

•DD&A Rate = Unamortized Cost / End of Period Reserves Adjusted for Current Period Production

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•Provision for DD&A = DD&A Rate x Current Period Production

Unamortized cost includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved properties, and equipment not placed in service.

Oil, NGLs, and natural gas reserve estimates have a significant impact on our DD&A rate. If future reserve estimates for a property or group of properties are revised downward, the DD&A rate will increase because of the revision. If reserve estimates are revised upward, the DD&A rate will decrease.

The DD&A expense on our oil and natural gas properties is calculated each quarter using period end reserve quantities adjusted for period production.

We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, we capitalize all costs incurred in the acquisition, exploration, and development of oil and natural gas properties. At the end of each quarter, the net capitalized costs of our oil and natural gas properties are limited to that amount which is the lower of unamortized costs or a ceiling. The ceiling is defined as the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (based on the unescalated 12-month average price on our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the cost of properties not being amortized, plus the lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are required to write-down the excess amount. A ceiling test write-down is a non-cash charge reducing earnings and shareholders’ equity in the period of occurrence, resulting in lower DD&A expense in future periods. A write-down cannot be reversed once incurred.

The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when the prices for oil, NGLs, and natural gas are depressed or if we have large downward revisions in our estimated proved oil, NGLs, and natural gas reserves. Application of these rules during periods of relatively low prices, even if temporary, increases the chance of a ceiling test write-down. At December 31, 2021, our reserves were calculated based on applying 12-month 2021 average unescalated prices of $66.56 per barrel of oil, $44.22 per barrel of NGLs, and $3.60 per Mcf of natural gas (then adjusted for price differentials) over the estimated life of each of our oil and natural gas properties.

Impairment of Other Property and Equipment. We review the carrying amounts of long-lived assets for potential impairment when events occur or changes in circumstances suggest these carrying amounts may not be recoverable. Changes that could prompt an assessment include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect our assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. Using different estimates and assumptions could result in materially different carrying values of our assets.

Asset Retirement Obligations. We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The estimated liabilities related to these future costs are recorded at the time the wells are drilled or acquired. We use historical experience to determine the estimated plugging costs considering the well's type, depth, physical location, and ultimate productive life. A risk-adjusted discount rate and an inflation factor are applied to estimate the present value of these obligations. We depreciate the capitalized asset retirement cost and accrete the obligation over time. Revisions to the obligations and assets are recognized at the appropriate risk-adjusted discount rate with a corresponding adjustment made to the full cost pool. Our mid-stream segment has property and equipment at locations leased or under right of way agreements which may require asset removal or site restoration, however, we are not able to reasonably measure the fair value of the obligations as the potential settlement dates are indeterminable.

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Warrant Liability. We recognize the fair value of the warrants as a derivative liability on our consolidated balance sheets with changes in the liability reported as loss on change in fair value of warrants in our consolidated statements of operations. The liability will continue to be adjusted to fair value at each reporting period until the warrants meet the definition of an equity instrument, at which time they will be reported as shareholders' equity and no longer subject to future fair value adjustments.

Bankruptcy Reorganization. We have applied Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852) in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 Cases, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings, are recorded in reorganization items, net on our accompanying consolidated statements of operations.

Fresh Start. The company qualified for and adopted fresh start accounting under the provisions of ASC 852. When applying ASC 852, an entity determines its reorganization value and enterprise value. Reorganization value, as determined under ASC 820, Fair Value Measurement, represents the fair value of the entity's total assets before the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The entity's enterprise value represents the estimated fair value of an entity’s long-term debt and equity. The assumptions used in estimating these values are inherently uncertain and require significant judgment.

Recently Issued Accounting Standards

Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 and ASU 2021-01 which provide and clarify optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs will be in effect for a limited time beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. We have not yet elected to use the optional guidance and continue to evaluate the options provided by ASU 2020-04 and ASU 2021-01.

Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging— Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The FASB issued ASU 2020-06 which simplifies the accounting for convertible instruments by removing certain accounting models which separate the embedded conversion features from the host contract for convertible instruments. The ASU further removes certain settlement conditions that are required for equity contracts to qualify for the derivative scope exception and simplifies the diluted earnings per share calculation in certain areas. The ASU is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We will adopt ASU 2020-06 effective January 1, 2022. The adoption of this ASU is not expected to have a material impact on our consolidated financial statements.

Recently Adopted Accounting Standards

Income Taxes (Topic 740)—Simplifying the Accounting for Income Taxes. The FASB issued ASU 2019-12 to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendment is effective for reporting periods beginning after December 15, 2020. The adoption of this standard did not have a material impact to our consolidated financial statements.

Financial Condition and Liquidity

Summary

Our financial condition and liquidity primarily depend on the cash flow from our operations and borrowings under our credit agreements. The principal factors determining our cash flow are:

•the amount of natural gas, oil, and NGLs we produce;

•the prices we receive for our natural gas, oil, and NGLs production;

•the use of our drilling rigs and the dayrates we receive for those drilling rigs; and

•the fees and margins we obtain from our natural gas gathering and processing contracts.

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We currently expect that cash and cash equivalents, cash generated from operations, and available funds under the Exit credit agreement and the Superior credit agreement are adequate to cover our liquidity requirements for at least the next 12 months.

Below is a summary of certain financial information for the periods indicated:


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020
			(In thousands)
Net cash provided by operating activities	$	175,969	$	29,807	$	44,956
Net cash provided by (used in) investing activities	36,205		(2,258)		(20,139)
Net cash provided by (used in) financing activities	(160,748)		(47,775)		7,552
Net increase (decrease) cash, restricted cash, and cash equivalents	$	51,426	$	(20,226)	$	32,369

Cash Flows from Operating Activities

Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production, the oil, NGL, and natural gas we produce, settlements of derivative contracts, third-party use for our drilling rigs and mid-stream services, and the rates we can charge for those services. Our cash flows from operating activities are also affected by changes in working capital.

Net cash provided by operating activities during the year ended December 31, 2021 increased by $101.2 million as compared to the year ended December 31, 2020 primarily due to increased operating profit in all three segments partially offset by changes in operating assets and liabilities related to the timing of cash receipts and disbursements.

Cash Flows from Investing Activities

We have historically dedicated a substantial portion of our capital budgets to our exploration for and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells. Although we have curtailed our spending throughout 2020 and into 2021, we expect the majority of future capital budgets to be focused on low cost capital projects to enhance production and reserves in this favorable price environment.

Net cash provided by (used in) investing activities increased by $58.6 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to proceeds received from the disposition of our corporate headquarters building and land, an increase in proceeds received from the disposition of other non-core assets, and a decrease in capital expenditures resulting from a decrease in the number of wells drilled and oil and gas property acquisitions, partially offset by the Superior gathering system acquisition.

Cash Flows from Financing Activities

Net cash provided by (used in) financing activities decreased by $120.5 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to higher payments on our credit agreements, the repurchase of common stock, lower borrowings under our credit agreements, distributions made to non-controlling interests, and lower bank overdrafts.

As of December 31, 2021, we had unrestricted cash and cash equivalents totaling $64.1 million, which includes $17.2 million of cash and cash equivalents held by Superior, and $19.2 million of outstanding borrowings, all of which was borrowed under the Superior credit agreement. Unit had no outstanding borrowings under the Exit credit agreement.

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Below, we summarize certain financial information as of December 31:


	Successor		Successor
	2021		2020
	(In thousands)
Working capital	$	5,792	$	2,575
Current portion of long-term debt	$	—	$	600
Long-term debt (1)	$	19,200	$	98,400
Shareholders' equity attributable to Unit Corporation	$	187,397	$	179,222

Working Capital

Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative activity. We had positive working capital of $5.8 million at December 31, 2021 compared to positive working capital of $2.6 million as of December 31, 2020. The increase in working capital is primarily due to higher cash and cash equivalents and accounts receivable, partially offset by higher current derivative liabilities, warrant liability, and accounts payable. Both the Superior credit agreement and the Exit credit agreement may be used for working capital. As of December 31, 2021, we had no outstanding borrowings under the Exit credit agreement and $19.2 million of outstanding borrowings under the Superior credit agreement. The effect of our derivatives decreased working capital by $40.9 million as of December 31, 2021 and decreased working capital by $1.0 million as of December 31, 2020.

Credit Agreements

Exit Credit Agreement. On the Effective Date, under the terms of the Plan, the company entered into an amended and restated credit agreement (the Exit credit agreement), providing for a $140.0 million senior secured revolving credit facility (RBL Facility) and a $40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC (together, the Borrowers), (ii) the guarantors party thereto, including the company and all of its subsidiaries existing as of the Effective Date (other than Superior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders party thereto from time to time (Lenders), and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (in such capacity, the Administrative Agent). The maturity date of borrowings under this Exit credit agreement is March 1, 2024.

Our Exit credit agreement is primarily used for working capital purposes as it limits the amount that can be borrowed for capital expenditures. These limitations restrict future capital projects using the Exit credit agreement. The Exit credit agreement also requires that proceeds from the disposition of certain assets be used to repay amounts outstanding.

On April 6, 2021, the company finalized the first amendment to the Exit credit agreement. Under the first amendment, the company reaffirmed its borrowing base of $140.0 million of the RBL, amended certain financial covenants, and received less restrictive terms as it relates to the disposition of assets and the use of proceeds from those dispositions.

On July 27, 2021, the company finalized the second amendment to the Exit credit agreement. Under the second amendment, the company obtained confirmation that the Term Loan had been paid in full prior to the amendment date and received one-time waivers related to the disposition of assets.

On October 19, 2021, the company finalized the third amendment to the Exit credit agreement. Under the third amendment, the company requested, and was granted, a reduction in the RBL borrowing base from $140.0 million to $80.0 million in addition to less restrictive terms as it relates to capital expenditures, required hedges, and the use of proceeds from the disposition of certain assets, while also amending certain financial covenants.

On March 30, 2022, the RBL Facility borrowing base of $80.0 million was reaffirmed.

During the year ended December 31, 2021, the company repaid $145.1 million of borrowings under the Exit credit agreement with cash generated from operations as well as from proceeds from divestitures of non-core assets. As of December 31, 2021, we had no outstanding long-term borrowings under the Exit credit agreement.

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Superior Credit Agreement. On May 10, 2018, Superior signed a five-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions (Superior credit agreement). The maturity date of borrowings under the Superior credit agreement is March 10, 2023. As of December 31, 2021, we had $19.2 million of borrowings and $0.5 million of letters of credit outstanding under the Superior credit agreement.

Capital Requirements

Oil and Natural Gas Segment Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward growth. Our decisions to increase our oil, NGLs, and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential, and opportunities to obtain financing, which provide us flexibility in deciding when and if to incur these costs.

Capital expenditures for oil and gas properties on the full cost method for the year ended December 31, 2021 by this segment, excluding a $0.5 million increase in the ARO liability, totaled $17.3 million. Capital expenditures for the four months ended December 31, 2020, excluding a $1.7 million reduction in the ARO liability, totaled $4.0 million while capital expenditures for the eight months ended August 31, 2020, excluding a $29.2 million reduction in the ARO liability and $0.4 million for acquisitions (including associated ARO), totaled $5.4 million. We participated in the completion of 12 gross wells (1.75 net wells) drilled by other operators during the year ended December 31, 2021 compared to 3 gross wells (0.30 net wells) drilled by other operators in which we participated during the four months ended December 31, 2020 and 16 gross wells (0.35 net wells) drilled by other operators in which we participated during the eight months ended August 31, 2020.

On June 25, 2021, the company entered into a purchase and sale agreement to which we agreed to sell substantially all of our wells and the leases related thereto located near Oklahoma City, Oklahoma for $19.5 million, subject to customary closing and post-closing adjustments. The divestiture closed on August 16, 2021, with an effective date of May 1, 2021. The sale of these assets did not result in a significant alteration of the full cost pool, and therefore no gain or loss was recognized.

On March 30, 2021, the company entered into a purchase and sale agreement to which we agreed to sell substantially all of our wells and the leases related thereto located in Reno and Stafford Counties, Kansas for $7.1 million, subject to customary closing and post-closing adjustments. This divestiture closed on May 6, 2021, with an effective date of February 1, 2021. The sale of these assets did not result in a significant alteration of the full cost pool and therefore, no gain or loss was recognized.

We also sold $5.0 million of other non-core oil and natural gas assets, net of related expenses, during the year ended December 31, 2021, compared to $0.4 million during the four months ended December 31, 2020, and $1.2 million during the eight months ended August 31, 2020. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.

Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. Capital expenditures for 2021 were primarily related to maintenance capital on operating drilling rigs. We also pursued the disposal or sale of our non-core, idle drilling rig fleet. We incurred $2.9 million in capital expenditures during the year ended December 31, 2021 compared to $0.6 million and $2.4 million during the four months ended December 31, 2020 and eight months ended August 31, 2020, respectively.

We sold non-core contract drilling assets for proceeds of $12.7 million, net of related expenses, during the year ended December 31, 2021, compared to $1.3 million during the four months ended December 31, 2020, and $4.8 million during the eight months ended August 31, 2020. These proceeds resulted in net gains of $10.1 million during the year ended December 31, 2021, compared to $0.5 million during the four months ended December 31, 2020, and $1.4 million during the eight months ended August 31, 2020.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. During the year ended December 31, 2021, our mid-stream segment incurred $24.5 million in capital expenditures (including the $13.0 million acquisition of a gathering and processing system in southern Kansas) compared to $1.3 million and $9.3 million during the four months ended December 31, 2020 and eight months ended August 31, 2020, respectively.

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Contractual Commitments

We had the following contractual commitments as of December 31, 2021: