UNIT CORP - Quarter Report: 2021 March (Form 10-Q)

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 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)			(I.R.S. Employer Identification No.)

8200 South Unit Drive,

Tulsa,

Oklahoma

74132

(Address of principal executive offices)

(Zip Code)

(918) 493-7700

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year,

if changed since last report)

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

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 obligation to file reports under 15(d) of the Securities Exchange Act of 1934 was 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. (Check one):

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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

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TABLE OF CONTENTS


		Page Number
	PART I. Financial Information

Item 1.	Financial Statements (Unaudited)	4











	Notes to Unaudited Condensed Consolidated Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	39

Item 4.	Controls and Procedures	40

	PART II. Other Information

Item 1.	Legal Proceedings	42

Item 1A.	Risk Factors	42

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42

Item 3.	Defaults On Senior Securities	42

Item 4.	Mine Safety Disclosures	42

Item 5.	Other Information	42

Item 6.	Exhibits	42

Signatures		42

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Forward-Looking 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. All statements, other than statements of historical facts, included or incorporated by reference in this document that addresses activities, events or developments we expect or anticipate will or may occur, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are used to identify forward-looking statements. This report modifies and supersedes documents filed by us before this report. In addition, certain information we file with the United States Securities Exchange Commission (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;

•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;

•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 assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and 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 several 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 risk 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;

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

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•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;

•our ability to remediate a material weakness in our internal controls over financial reporting;

•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 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 3uantitative and Qualitative Disclosures About Market Risk-Energy Commodity Market Risk.”

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	March 31, 2021		December 31, 2020
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	25,188	$	12,145
Restricted cash	—		569
Accounts receivable, net of allowance for credit losses of $4,265 and $3,783 at March 31, 2021 and December 31, 2020, respectively	59,863		57,846



Current income tax receivable	34		1,150

Prepaid expenses and other	8,444		11,212
Total current assets	93,529		82,922
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties	240,285		238,581
Unproved properties not being amortized	49		1,591
Drilling equipment	63,764		63,687
Gas gathering and processing equipment	252,463		251,404
Land and building	32,635		32,635
Transportation equipment	3,335		3,130
Other	8,667		9,961
	601,198		600,989
Less accumulated depreciation, depletion, amortization, and impairment	71,921		54,189
Net property and equipment	529,277		546,800


Right of use asset (Note 13)	4,443		5,592
Other assets	15,616		14,389
Total assets (1)	$	642,865	$	649,703

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED


	March 31, 2021		December 31, 2020
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	34,552	$	37,368
Accrued liabilities (Note 7)	23,108		25,204
Current operating lease liability (Note 13)	3,648		4,075
Current portion of long-term debt (Note 8)	800		600
Current derivative liabilities (Note 11)	14,022		1,047
Warrant liability (Note 12)	885		885
Current portion of other long-term liabilities (Note 8)	10,418		11,168
Total current liabilities	87,433		80,347
Long-term debt (Note 8)	78,200		98,400
Non-current derivative liabilities (Note 11)	11,211		4,659
Operating lease liability (Note 13)	741		1,445
Other long-term liabilities (Note 8)	40,188		39,259
Commitments and contingencies (Note 14)
Shareholders’ equity:
Preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued	—		—
Common stock, $0.01 par value, 25,000,000 shares authorized, 12,000,000 shares issued as of March 31, 2021 and December 31, 2020	120		120
Capital in excess of par value	197,316		197,242

Retained deficit	(20,077)		(18,140)
Total shareholders’ equity attributable to Unit Corporation	177,359		179,222
Non-controlling interests in consolidated subsidiaries	247,733		246,371
Total shareholders' equity	425,092		425,593
Total liabilities(1) and shareholders’ equity	$	642,865	$	649,703

_______________________

(1)Unit Corporation's consolidated total assets as of March 31, 2021 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $55.7 million and $239.7 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of March 31, 2021 include total current and long-term liabilities of the VIE of $29.6 million and $1.7 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2020 include total current and long-term assets of the VIE of $45.8 million and $247.8 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2020 include total current and long-term liabilities of the VIE of $28.4 million and $2.6 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 15 – Variable Interest Entity Arrangements.

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)


	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
	(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	55,024	$	48,522
Contract drilling	15,674		36,632
Gas gathering and processing	50,199		37,222
Total revenues	120,897		122,376
Expenses:
Operating costs:
Oil and natural gas	19,149		30,663
Contract drilling	11,871		25,449
Gas gathering and processing	40,543		27,611
Total operating costs	71,563		83,723
Depreciation, depletion, and amortization	17,511		61,617
Impairments (Note 3)	—		741,924
Loss on abandonment of assets (Note 3)	—		17,554
General and administrative	6,289		11,553
(Gain) loss on disposition of assets	(472)		390
Total operating expenses	94,891		916,761
Income (loss) from operations	26,006		(794,385)
Other income (expense):
Interest, net	(2,706)		(13,257)
Gain (loss) on derivatives	(22,831)		483
Reorganization items, net	(1,136)		—
Other, net	76		60
Total other income (expense)	(26,597)		(12,714)
Loss before income taxes	(591)		(807,099)
Income tax benefit:
Current	—		(917)
Deferred	—		(2,508)
Total income taxes	—		(3,425)
Net loss	(591)		(803,674)
Net income (loss) attributable to non-controlling interest	1,346		(33,180)
Net loss attributable to Unit Corporation	(1,937)		(770,494)
Net loss attributable to Unit Corporation per common share (Note 6):
Basic	$	(0.16)	$	(14.50)
Diluted	$	(0.16)	$	(14.50)

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (UNAUDITED)


	Three Months Ended March 31, 2021
	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Capital in Excess of Par Value		Retained Earnings (Deficit)		Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, December 31, 2020 (Successor)	$	120	$	197,242	$	(18,140)	$	246,371	$	425,593
Net income (loss)	—		—		(1,937)		1,346		(591)
Activity in employee compensation plans	—		74		—		16		90
Balances, March 31, 2021 (Successor)	$	120	$	197,316	$	(20,077)	$	247,733	$	425,092


	Three Months Ended March 31, 2020
	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Capital in Excess of Par Value		Retained Earnings (Deficit)		Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, December 31, 2019 (Predecessor)	$	10,591	$	644,152	$	199,135	$	201,757	$	1,055,635
Net loss	—		—		(770,494)		(33,180)		(803,674)
Activity in employee compensation plans	103		2,391		—		31		2,525
Balances, March 31, 2020 (Predecessor)	$	10,694	$	646,543	$	(571,359)	$	168,608	$	254,486

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
	(In thousands)
OPERATING ACTIVITIES:
Net loss	$	(591)	$	(803,674)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	17,511		61,617
Impairments (Note 3)	—		741,924
Loss on abandonment of assets (Note 3)	—		17,554
Amortization of debt issuance costs and debt discount	—		567
(Gain) loss on derivatives (Note 11)	22,831		(483)
Cash receipts (payments) on derivatives settled (Note 11)	(3,304)		551
(Gain) loss on disposition of assets	(472)		390
Deferred tax benefit	—		(2,508)
Employee stock compensation plans	90		2,568
Credit loss expense	482		—
ARO liability accretion (Note 9)	461		596
Contract assets and liabilities, net (Note 4)	812		808
Noncash reorganization items	760		—
Other, net	(79)		(740)

Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(2,498)		28,277
Material and supplies	—		35
Prepaid expenses and other	1,586		420
Accounts payable	(4,043)		(12,341)
Accrued liabilities	(4,287)		(4,840)
Income taxes	1,116		(917)
Contract advances	(71)		108

Net cash provided by operating activities	30,304		29,912
INVESTING ACTIVITIES:
Capital expenditures	(2,034)		(17,528)
Producing properties and other acquisitions	—		(210)
Proceeds from disposition of property and equipment	4,462		1,751


Net cash provided by (used in) investing activities	2,428		(15,987)
FINANCING ACTIVITIES:
Borrowings under line of credit	2,700		71,400
Payments under line of credit	(22,700)		(35,100)

Net payments on finance leases	(1,067)		(1,026)
Employee taxes paid by withholding shares	—		(43)





Bank overdrafts	809		(8,733)
Net cash provided by (used in) financing activities	(20,258)		26,498
Net increase in cash, restricted cash and cash equivalents	12,474		40,423
Cash, restricted cash, and cash equivalents, beginning of period	12,714		571
Cash, restricted cash, and cash equivalents, end of period	$	25,188	$	40,994

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - CONTINUED


	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
	(In thousands)
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Interest paid (net of capitalized)	$	2,438	$	2,141
Income taxes	(1,116)		—
Reorganization items	377		—

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(1,920)		4,812
Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations	(26)		3,404
Non-cash trade of property, plant, and equipment	—		548

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – ORGANIZATION AND BUSINESS

Unless the context clearly indicates otherwise, references in this report to “Unit”, “company”, “we”, “our”, “us”, or like terms refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers to Superior of which we own 50%.

We are primarily engaged in the development, acquisition, and production of oil and natural gas properties, the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas. Our operations are all in the United States and are organized in the following three reporting segments: (1) Oil and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream.

Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company (UPC), we develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Kansas, Louisiana, Montana, North Dakota, Utah, and Wyoming.

Contract Drilling. Carried out by our subsidiary, Unit Drilling Company (UDC), we drill onshore oil and natural gas wells for a wide range of other oil and natural gas companies as well as for our own account. Our drilling operations are mainly in Oklahoma, Texas, New Mexico, Wyoming, and North Dakota.

Mid-Stream. Carried out by our subsidiary, Superior, we buy, sell, gather, transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

On May 22, 2020 (Petition Date), Unit together with its wholly owned subsidiaries, UDC; UPC; 8200 Unit Drive, L.L.C. (8200 Unit); Unit Drilling Colombia, L.L.C. (Unit Drilling Colombia); and Unit Drilling USA Colombia, L.L.C. (Unit Drilling USA, together with Unit, UPC, UDC, 8200 Unit and Unit Drilling Colombia, the Debtors), filed voluntary petitions (Bankruptcy 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 (Bankruptcy Court). The Chapter 11 proceedings were jointly administered under Case No. 20-32740 (DRJ) (Chapter 11 Cases).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” (the Plan) [Docket No. 340] (Confirmation Order) confirming the Plan and approving the disclosure statement on a final basis. On September 3, 2020 (Effective Date) the conditions to effectiveness for the Plan were satisfied, and the Debtors emerged from Chapter 11.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (GAAP) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2020 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 31, 2021.

In the opinion of management, the unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) and are fairly stated. Our financial statements are prepared in conformity with GAAP, which requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and notes. Actual results may differ from those estimates. The results for interim periods are necessarily indicative of annual results.

In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 852, Reorganizations, the Company adopted fresh start accounting upon emergence from the Chapter 11 Cases resulting in the Company becoming a new entity for financial reporting purposes. We evaluated the events between September 1, 2020 and September 3, 2020 and concluded that the use of an accounting convenience date of September 1, 2020 (Fresh Start Reporting

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Date) would not have a material impact to the condensed consolidated financial statements. This was reflected in our condensed consolidated balance sheet as of September 1, 2020. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 1, 2020, are not comparable to the Condensed Consolidated Financial Statements and Notes before that date. To facilitate the financial statement presentations, we refer to the reorganized company in these unaudited condensed consolidated financial statements and notes as the "Successor" for periods subsequent to August 31, 2020, and "Predecessor" for periods prior to September 1, 2020. Furthermore, the unaudited condensed consolidated financial statements and notes have been presented with a "black line" division to delineate the lack of comparability between the Predecessor and Successor.

We consolidate the activities of Superior Pipeline Company, L.L.C. (Superior), a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, (SP Investor) which qualifies as a Variable Interest Entity (VIE) under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power to direct those activities that most significantly affect the economic performance of Superior as further described in Note 15 – Variable Interest Entity Arrangements.

Certain amounts in this report for prior periods have been reclassified to conform to current year presentation. There was no impact from these reclassifications to consolidated net income/(loss) or shareholders' equity.

Recent Accounting Pronouncements

Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 which provides 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 ASU is intended to help stakeholders during the global market-wide reference rate transition period. The amendments within this ASU 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. The amendments will not have a material impact on our consolidated financial statements.

Adopted 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 amendments were effective for reporting periods beginning after December 15, 2020. This standard had no material impact on our consolidated financial statements.

NOTE 3 – IMPAIRMENTS

We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of those assets may not be recoverable, and changes to our estimates could affect our assessment of asset recoverability.

Oil and Natural Gas Properties

There were no impairments recorded during the Successor Period of the three months ended March 31, 2021.

During the first quarter of 2020, due to the increased uncertainty in our business, we determined our undeveloped acreage would not be fully developed and thus the carrying values of certain of our unproved oil and gas properties were not recoverable resulting in an impairment of $226.5 million. That impairment had a corresponding increase to our depletion base and contributed to our recorded full cost ceiling impairment during the first quarter of 2020. We recorded a non-cash full cost ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax) in the first quarter of 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above.

In addition to the impairment evaluations of our proved and unproved oil and gas properties in the first quarter of 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast, we determined that some were no longer expected to be used and wrote off the assets for total expense of $17.6 million during the first quarter of 2020. These amounts are reported in loss on abandonment of assets in our Unaudited Condensed Consolidated Statements of Operations.

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Contract Drilling

There were no impairments recorded during the Successor Period of the three months ended March 31, 2021.

At March 31, 2020, due to market conditions, we performed impairment testing on two asset groups which were comprised of our SCR diesel-electric drilling rigs and our BOSS drilling rigs. We concluded that the net book value of the SCR drilling rigs asset group was not recoverable through estimated undiscounted cash flows and recorded a non-cash impairment charge of $407.1 million in the first quarter of 2020. We also recorded an additional non-cash impairment charges of $3.0 million for other miscellaneous drilling equipment. These charges are included within impairment charge in our Unaudited Condensed Consolidated Statements of Operations.

We used the income approach to determine the fair value of the SCR drilling rigs asset group. This approach uses significant assumptions including management’s best estimates of the expected future cash flows and the estimated useful life of the asset group. Fair value determination requires a considerable amount of judgement and is sensitive to changes in underlying assumptions and economic factors. As a result, there is no assurance the fair value estimates made for the impairment analysis will be accurate in the future.

We concluded that no impairment was needed as of March 31, 2020 on the BOSS drilling rigs asset group as the undiscounted cash flows exceeded the carrying value of the asset group. The carrying value of the asset group was approximately $242.5 million at March 31, 2020. The estimated undiscounted cash flows of the BOSS drilling rigs asset group exceeded the carrying value by a relatively minor margin. Some of the more sensitive assumptions used in evaluating the contract drilling rigs asset groups for potential impairment include forecasted utilization, gross margins, salvage values, discount rates, and terminal values.

Mid-stream

There were no impairments recorded during the Successor Period of the three months ended March 31, 2021.

During the first quarter of 2020, we determined that the carrying value of certain long-lived asset groups in southern Kansas, and central Oklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. Based on the estimated fair value of the asset groups, we recorded non-cash impairment charges of $64.0 million. These charges are included within impairment charges in our Unaudited Condensed Consolidated Statement of Operations.

NOTE 4 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is how we disaggregate our revenue and report our segment revenue (as reflected in Note 16 – Industry Segment Information). Revenue from the oil and natural gas segment is from sales of our oil and natural gas production. Revenue from the contract drilling segment comes from contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas and NGLs and selling those commodities.

Oil and Natural Gas Revenues

Certain costs—as either a deduction from revenue or as an expense—are determined based on when control of the commodity is transferred to our customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing, and transportation costs included as part of the contract price with the customer on transfer of control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity represent operating costs.

Contract Drilling Revenues

Mobilization and de-mobilization charges from our drilling contracts do not relate to a distinct good or service. These revenues should be deferred and recognized ratably over the related contract term that drilling services are provided. We have continued to record these revenues as a distinct service and the impact to our financial statements was immaterial. As of March 31, 2021, we had six contract drilling contracts with terms ranging from two months to almost one year.

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Most of our drilling contracts have an original term of less than one year. The remaining performance obligations under the contracts with a longer duration are not material.

Mid-stream Contracts Revenues

Revenues are generated from fees earned for gas gathering and processing services provided to a customer or by selling hydrocarbons to other mid-stream companies. The typical revenue contracts used by this segment are gas gathering and processing agreements as well as product sales.

Contracts for gas gathering and processing services may include terms for demand fees or shortfall fees. Demand fees represent an arrangement where a customer agrees to pay a fixed fee for a contractually agreed upon pipeline capacity, which results in performance obligations for each individual period of reservation. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized.

The table below shows the changes in our mid-stream contract asset and contract liability balances during periods presented associated with demand fees and the impact to gas gathering and processing revenues:



	Classification on the Consolidated Balance Sheets	March 31, 2021		December 31, 2020		Change
		(In thousands)
Assets
Current contract assets	Prepaid expenses and other	$	4,735	$	6,084	$	(1,349)
Non-current contract assets	Other assets	—		173		(173)
Total contract assets		$	4,735	$	6,257	$	(1,522)

Liabilities
Current contract liabilities	Current portion of other long-term liabilities	$	2,332	$	2,583	$	(251)
Non-current contract liabilities	Other long-term liabilities	1,130		1,589		(459)
Total contract liabilities		3,462		4,172		(710)
Contract assets (liabilities), net		$	1,273	$	2,085	$	(812)

Included below is the adjustment to demand fees from adopting ASC 606 over the remaining term of the contracts as of March 31, 2021.


Contract	Remaining Term of Contract	2021		2022		2023 and beyond		Total Remaining Impact to Revenue
		(In thousands)
Demand fee contracts	2 - 8 years	$	(2,689)	$	1,380	$	36	$	(1,273)

NOTE 5 – DIVESTITURES

Oil and Natural Gas

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 will not result in a significant alteration of the full cost pool, and therefore no gain or loss will be recognized.

We sold $1.7 million of non-core oil and natural gas assets, net of related expenses, during the first three months of the Successor Period 2021, compared to $0.6 million during the first three months of the Predecessor Period 2020. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.

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NOTE 6 – LOSS PER SHARE

Information related to the calculation of loss per share attributable to Unit Corporation is as follows:


	Loss (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended March 31, 2021 (Successor)
Basic loss attributable to Unit Corporation per common share	$	(1,937)	12,000	$	(0.16)
For the three months ended March 31, 2020 (Predecessor)
Basic loss attributable to Unit Corporation per common share	$	(770,494)	53,131	$	(14.50)

All outstanding shares issued during the Predecessor period were cancelled upon emergence from bankruptcy.

NOTE 7 – ACCRUED LIABILITIES

Accrued liabilities consisted of:



	March 31, 2021		December 31, 2020
	(In thousands)
Employee costs	$	6,198	$	8,878
Lease operating expenses	6,114		6,405
Capital expenditures	5,212		3,461
Taxes	3,396		2,324
Interest payable	300		884
Legal settlement	—		2,070
Other	1,888		1,182
Total accrued liabilities	$	23,108	$	25,204

NOTE 8 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

As of the date indicated, our long-term debt consisted of the following:


	March 31, 2021		December 31, 2020
	(In thousands)
Current portion of long-term debt:
Exit credit agreement with an average interest rate of 6.7% and 6.6% at March 31, 2021 and December 31, 2020, respectively	$	800	$	600
Long-term debt:
Exit credit agreement with an average interest rate of 6.7% and 6.6% at March 31, 2021 and December 31, 2020, respectively	$	78,200	$	98,400

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. Revolving Loans and Term Loans (each as defined in the Exit credit agreement) may be Eurodollar Loans or ABR Loans (each as defined in the Exit credit

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agreement). Revolving Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate (as defined in the Exit credit agreement) for the applicable interest period plus 525 basis points. Revolving Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate (as defined in the Exit credit agreement) plus 425 basis points. Term Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate for the applicable interest period plus 625 basis points. Term Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate plus 525 basis points.

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, among others, as it relates to the disposition of assets and the use of proceeds from those dispositions.

The Exit credit agreement requires the company to comply with certain financial ratios, including a covenant that the company will not permit the Net Leverage Ratio (as defined in the Exit credit agreement) as of the last day of the fiscal quarters ending (i) December 31, 2020 and March 31, 2021, to be greater than 4.00 to 1.00, (ii) June 30, 2021, September 30, 2021, December 31, 2021, March 31, 2022, and June 30, 2022, to be greater than 3.75 to 1.00, and (iii) September 30, 2022 and any fiscal quarter thereafter, to be greater than 3.50 to 1.00. In addition, beginning with the fiscal quarter ending December 31, 2020, the company may not (a) permit the Current Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 1.00 to 1.00 or (b) permit the Interest Coverage Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 2.50 to 1.00. The Exit credit agreement also contains provisions, among others, that limit certain capital expenditures, and require certain hedging activities. The Exit credit agreement further requires the company provide Quarterly Financial Statements within 45 days after the end of each of the first three quarters of each fiscal year and Annual Financial Statements within 90 days after the end of each fiscal year. As of March 31, 2021, Unit was in compliance with these covenants.

The Exit credit agreement is secured by first-priority liens on substantially all of the personal and real property assets of the Borrowers and the Guarantors, including without limitation the company’s ownership interests in Superior Pipeline Company, L.L.C.

At March 31, 2021, we had $0.8 million and $78.2 million outstanding current and long-term borrowings, respectively, under the Exit credit agreement.

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. The amounts borrowed under the Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) the Thirty-Day LIBOR Rate (as defined in the Superior credit agreement)) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by mortgage liens on certain of Superior’s processing plants and gathering systems. The Superior credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to the Administrative Agent in the London Interbank Market, the Administrative Agent may select a replacement index.

Superior is charged a commitment fee of 0.375% on the amount available but not borrowed which varies based on the amount borrowed as a percentage of the total borrowing base. Superior paid $1.7 million in origination, agency, syndication, and other related fees. These fees are being amortized over the life of the Superior credit agreement.

The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. The agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As of March 31, 2021, Superior was in compliance with these covenants.

The Superior credit agreement is used to fund capital expenditures and acquisitions and provide general working capital and letters of credit. As of March 31, 2021, we did not have any outstanding borrowings under our Superior credit agreement.

Unit is not a party to and does not guarantee Superior's credit agreement.

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Other Long-Term Liabilities

Other long-term liabilities consisted of the following:



	March 31, 2021		December 31, 2020
	(In thousands)
Asset retirement obligation (ARO) liability	$	23,843	$	23,356
Workers’ compensation	11,735		10,164
Finance lease obligations	2,149		3,216
Contract liability	3,462		4,172
Separation benefit plans	3,859		4,201
Gas balancing liability	4,238		3,997
Other long-term liability	1,320		1,321
	50,606		50,427
Less current portion	10,418		11,168
Total other long-term liabilities	$	40,188	$	39,259

NOTE 9 – 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 plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All our AROs relate to the plugging costs associated with our oil and gas wells.

The following table shows certain information about our estimated AROs for the periods indicated:


	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
	(In thousands)
ARO liability, January 1:	$	23,356	$	66,627
Accretion of discount	461		596
Liability incurred	—		314
Liability settled	(16)		(319)
Liability sold	(2)		(15)
Revision of estimates (1)	44		(3,384)
ARO liability, March 31:	23,843		63,819
Less current portion	2,161		1,470
Total long-term ARO	$	21,682	$	62,349

_______________________

1.Plugging liability estimates were revised in 2020 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 10 – STOCK-BASED COMPENSATION

On the Effective Date, the Board adopted the Unit Corporation Long Term Incentive Plan (LTIP) to incentivize employees, officers, directors and other service providers of the company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Board or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, performance awards, substitute awards or any combination of the foregoing. Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the LTIP, 903,226 shares of new common stock of the reorganized company (New Common Stock) have been reserved for issuance pursuant to awards under the LTIP. New Common Stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash, or otherwise terminated without delivery of shares and shares

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withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the LTIP. The LTIP will be administered by the Board or a committee thereof.

No shares under the LTIP have been awarded since the Effective Date through March 31, 2021.

Also on the Effective Date, the company's equity-based awards outstanding immediately before the Effective Date were cancelled. The cancellation of the awards resulted in an acceleration of unrecorded stock compensation expense during the Predecessor Period. Under the Plan, the company issued Warrants to holders of those equity-based awards that were outstanding immediately before the Effective Date who did not opt out of releases under the Plan.

For restricted stock awards and stock options, we had:


	Predecessor
	Three Months Ended March 31, 2020
	(In millions)
Recognized stock compensation expense	$	2.5

Tax benefit on stock-based compensation	$	0.6

We did not grant any stock options or restricted stock awards during the three month period ending March 31, 2020.

NOTE 11 – DERIVATIVES

Commodity Derivatives

We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions as well as certain requirements stipulated in the Exit credit agreement. For further details, see Note 8 – Long-Term Debt and Other Long-Term Liabilities. As of March 31, 2021, our derivative transactions consisted of the following types of hedges:

•Basis/Differential Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the commodity and pay or receive the published index price at the specified delivery point. We use basis/differential swaps to hedge the price risk between NYMEX and its physical delivery points.

•Swaps. We receive or pay a fixed price for the commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

•Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.

We do not engage in derivative transactions for speculative purposes. All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations.

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At March 31, 2021, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Apr'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$(0.215)

NGPL TEXOK

Apr'21 - Oct'21

Natural gas - swap

50,000 MMBtu/day

$2.818

IF - NYMEX (HH)

Nov'21 - Dec'21

Natural gas - swap

45,000 MMBtu/day

$2.900

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - swap

5,000 MMBtu/day

$2.605

IF - NYMEX (HH)

Jan'23 - Dec'23

Natural gas - swap

22,000 MMBtu/day

$2.456

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - collar

35,000 MMBtu/day

$2.50 - $2.68

IF - NYMEX (HH)

Apr'21 - Dec'21

Crude oil - swap

3,373 Bbl/day

$46.16

WTI - NYMEX

Jan'22 - Dec'22

Crude oil - swap

2,300 Bbl/day

$42.25

WTI - NYMEX

Jan'23 - Dec'23

Crude oil - swap

1,300 Bbl/day

$43.60

WTI - NYMEX

The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:


		Derivative Liabilities
		Fair Value
	Balance Sheet Location	March 31, 2021		December 31, 2020
		(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	14,022	$	1,047
Long-term	Non-current derivative liability	11,211		4,659
Total derivative liabilities		$	25,233	$	5,706

All our counterparties are subject to master netting arrangements. If we have a legal right of set-off, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets.

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the periods indicated:


	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
	(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $(3,304) and $551, respectively	$	(22,831)	$	483
	$	(22,831)	$	483

NOTE 12 – FAIR VALUE MEASUREMENTS

Fair value is defined as the amount that would be received from the sale of an asset or paid for transferring a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows:

•Level 1—unadjusted quoted prices in active markets for identical assets and liabilities.

•Level 2—significant observable pricing inputs other than quoted prices included within level 1 either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.

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•Level 3—generally unobservable inputs developed based on the best information available and may include our own internal data.

The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments.

The following tables set forth our recurring fair value measurements:


	March 31, 2021
	Level 2		Level 3		Effect of Netting		Net Amounts Presented

Financial assets (liabilities):
Commodity derivatives:
Assets	$	1,899	$	—	$	(1,899)	$	—
Liabilities	(27,132)		—		1,899		(25,233)
Total commodity derivatives	$	(25,233)	$	—	$	—	$	(25,233)


	December 31, 2020
	Level 2		Level 3		Effect of Netting		Net Amounts Presented

Financial assets (liabilities):
Commodity derivatives:
Assets	$	3,436	$	—	$	(3,436)	$	—
Liabilities	(9,142)		—		3,436		(5,706)
Total commodity derivatives	$	(5,706)	—		—		(5,706)

All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties and no collateral has been posted as of March 31, 2021.

We used the following methods and assumptions to estimate the fair values of the assets and liabilities in the table above. There were no transfers between Level 2 and Level 3 financial assets (liabilities).

Level 2 Fair Value Measurements

Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index.

Level 3 Fair Value Measurements

Commodity Derivatives. The fair values of our natural gas and crude oil three-way collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.

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The following table is a reconciliation of our Level 3 fair value measurements:


	Net Derivatives
	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
	(In thousands)
Beginning of period	$	—	$	1,204
Total gains or losses (realized and unrealized):
Included in earnings (1)	—		563
Settlements	—		(819)
End of period	$	—	$	948
Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period	$	—	$	(256)

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1.Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives.

Our valuation at March 31, 2021 reflected that the risk of non-performance was immaterial.

Warrants. Warrants are recorded at their fair value upon utilizing the Black-Scholes-Merton option model. The inputs to the model require judgement, including estimating the strike price, expected term and the associated volatility. At March 31, 2021, the Warrants have a fair value of $0.9 million and will continue to be adjusted to fair value at each reporting period until determined to be an equity instrument, at which time they will be reported as Shareholders' equity and no longer be subject to future fair value adjustment.

Fair Value of Other Financial Instruments

This disclosure of the estimated fair value of financial instruments is made under accounting guidance for financial instruments. We have determined the estimated fair values by using market information and certain valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. Using different market assumptions or valuation methodologies may have a material effect on our estimated fair value amounts.

At March 31, 2021, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature.

Fair Value of Non-Financial Instruments

The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of our AROs is presented in Note 9 – Asset Retirement Obligations.

NOTE 13 – LEASES

Lease Agreements. We lease certain office space, land, and equipment, including pipeline equipment and office equipment. Our lease payments are generally straight-line and the exercise of lease renewal options, which vary in term, is at our sole discretion. We include renewal periods in our lease term if we are reasonably certain to exercise available renewal options. Our lease agreements do not include options to purchase the leased property.

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The following table sets forth the maturity of our operating lease liabilities as of March 31, 2021:


	Amount
	(In thousands)
Ending March 31,
2022	$	3,760
2023	661
2024	29
2025	12
2026	12
2027 and beyond	60
Total future payments	4,534
Less: Interest	145
Present value of future minimum operating lease payments	4,389
Less: Current portion	3,648
Total long-term operating lease payments	$	741

Finance Leases under ASC 842

In 2014, Superior entered into finance lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $2.1 million current portion of the finance lease obligations is included in current portion of other long-term liabilities in the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2021. These finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases were $0.1 million at March 31, 2021. At the end of the term, Superior has the option to purchase the assets at 10% of their then fair market value.

The following table sets forth the maturity of our finance lease liabilities as of March 31, 2021:


	Amount
Ending March 31,	(In thousands)
2022	$	2,226
Total future payments	2,226
Less payments related to:
Maintenance	72
Interest	5
Present value of future minimum finance lease payments	2,149
Less: Current portion	2,149
Total long-term finance lease payments	$	—

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The following table shows information about our lease assets and liabilities in our Unaudited Condensed Consolidated Balance Sheets:


	Classification on the Consolidated Balance Sheet	March 31, 2021		December 31, 2020
		(In thousands)
Assets
Operating right of use assets	Right of use assets	$	4,443	$	5,592
Finance right of use assets	Property, plant, and equipment, net	7,032		7,281
Total right of use assets		$	11,475	$	12,873

Liabilities
Current liabilities:
Operating lease liabilities	Current operating lease liabilities	$	3,648	$	4,075
Finance lease liabilities	Current portion of other long-term liabilities	2,149		3,216
Non-current liabilities:
Operating lease liabilities	Operating lease liabilities	741		1,445
Finance lease liabilities	Other long-term liabilities	—		—
Total lease liabilities		$	6,538	$	8,736

The following table shows certain information related to the lease costs for our finance and operating leases for the periods indicated:



	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
	(In thousands)
Components of total lease cost:
Amortization of finance leased assets	$	1,067	$	1,025
Interest on finance lease liabilities	29		70
Operating lease cost	1,047		1,244
Short-term lease cost (1)	1,444		3,991
Variable lease cost	58		82
Total lease cost	$	3,645	$	6,412

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1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $0.1 million and $1.0 million for the first three months of 2021 and 2020, respectively.

The following table shows supplemental cash flow information related to leases for the periods indicated:


	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
	(In thousands)
Cash paid for amounts in the measurement of lease liabilities:
Operating cash flows for operating leases	$	1,048	$	1,333
Financing cash flows for finance leases	$	1,067	$	1,025

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The following table shows certain information related to the weighted average remaining lease terms and the weighted average discount rates for our operating and finance leases:


	Weighted Average Remaining Lease Term	Weighted Average Discount Rate (1)
	(In years)
Operating leases	1.4	4.30%
Finance leases	0.4	4.00%

_______________________

1.Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.

NOTE 14 – COMMITMENTS AND CONTINGENCIES

Commitments

We have firm transportation commitments to transport our natural gas from various systems for approximately $0.8 million over the next twelve months and $0.3 million for the nine months thereafter.

During the second quarter of 2018, as part of the Superior transaction (see Note 15 – Variable Interest Entity Arrangements), we entered into a contractual obligation committing us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. For each dollar of the $150.0 million we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our ownership interest in our consolidated mid-stream subsidiary. At March 31, 2021, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.6 million. The total amount spent towards the $150.0 million as of March 31, 2021 was $24.8 million. We do not anticipate meeting the contractual obligation over the remaining commitment period.

Environmental

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. Any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees expected to devote significant time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property.

We have not historically experienced significant environmental liability while being a contract driller since the greatest portion of that risk is borne by the operator. Any liabilities we have incurred have been small and were resolved while the drilling rig was on the location. Those costs were in the direct cost of drilling the well.

Litigation

The company is subject to litigation and claims arising in the ordinary course of business which may include environmental, health and safety matters, or more routine employment related claims. The company accrues for such items when a liability is both probable and the amount can be reasonably estimated. As new information becomes available or because of legal or administrative rulings in similar matters or a change in applicable law, the company's conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. Although we are insured against various risks, there is no assurance that the nature and amount of that insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.

On May 22, 2020, the Debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 Cases automatically stayed all the proceedings and actions against the Debtors (other than certain regulatory enforcement matters). The Debtors emerged from the Chapter 11 Cases on the Effective Date. On the Effective Date, the automatic stay was terminated and replaced with the injunction provisions in the Confirmation Order and the Plan.

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In 2013, the company’s exploration and production subsidiary, UPC, drilled a well in Beaver County, Oklahoma. Certain operational issues arose and one of the working interest owners in the well filed a lawsuit claiming that UPC’s actions violated its duties under the joint operating agreement and caused damages to the owners in the well. The case went to trial in January 2019 and the jury issued a verdict in favor of the working interest owner, awarding $2.4 million in damages, including pre- and post-judgment interest. UPC appealed the verdict, and while it was pending review in the Oklahoma Court of Civil Appeals, UPC finalized a settlement agreement with the working interest owner for $2.1 million in February 2021.

The commencement of the Chapter 11 Cases automatically stayed all proceedings and actions against the Predecessor company (other than certain regulatory enforcement matters). Effective at emergence from the Chapter 11 Cases, the automatic stay was terminated and replaced with the injunction provisions in the Confirmation Order and the Plan.

Below is a summary of two lawsuits and the respective treatment of those cases in the Chapter 11 Cases.

Cockerell Oil Properties, Ltd., v. Unit Petroleum Company, No. 16-cv-135-JHP, United States District Court for the

Eastern District of Oklahoma.

On March 11, 2016, a putative class action lawsuit was filed against UPC styled Cockerell Oil Properties, Ltd., v. Unit Petroleum Company in LeFlore County, Oklahoma. We removed the case to federal court in the Eastern District of Oklahoma. The plaintiff alleges that UPC wrongfully failed to pay interest with respect to late paid oil and gas proceeds under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney fees. Plaintiff is seeking relief on behalf of royalty and working interest owners in our Oklahoma wells.

Chieftain Royalty Company v. Unit Petroleum Company, No. CJ-16-230, District Court of LeFlore County, Oklahoma.

On November 3, 2016, a putative class action lawsuit was filed against UPC styled Chieftain Royalty Company v. Unit Petroleum Company in LeFlore County, Oklahoma. The plaintiff alleges that UPC breached its duty to pay royalties on natural gas used for fuel off the lease premises. The lawsuit seeks actual and punitive damages, an accounting, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of Oklahoma citizens who are or were royalty owners in our Oklahoma wells.

Pending Settlement

In August 2020, UPC reached an agreement to settle these class actions. Under the settlement, UPC agreed to recognize class proof of claims in the amount of $15.75 million for Cockerell Oil Properties, Ltd. vs. Unit Petroleum Company, and $29.25 million in Chieftain Royalty Company vs. Unit Petroleum Company. This settlement is subject to certain conditions, including approval by the United States Bankruptcy Court for the Southern District of Texas, Houston Division in Case No. 20-32740 under the caption In re Unit Corporation, et al. Under the Plan, these settlements will be treated as allowed general unsecured claims against UPC. And, in accordance with the Plan, the settlement amounts will be satisfied by distribution of the plaintiffs’ proportionate share of New Common Stock.

Winter Storm

In February 2021, a severe winter storm impacted many of our operating areas in Oklahoma, Texas, and Kansas, resulting in certain disruptions to our operations. Although some uncertainties remain as to the ultimate impact and severity of these disruptions, we do not believe any such matters will have a material impact on our financial position.

NOTE 15 – VARIABLE INTEREST ENTITY ARRANGEMENTS

On April 3, 2018 we sold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. 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, like operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $263,280. Superior's creditors have no recourse to our general credit. Unit is not a party to and does not guarantee Superior's credit agreement. The obligations under Superior's credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.

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The Agreement specifies how future distributions are to be allocated among the Members. Future distributions may be from available cash or made in conjunction with a sale event (both as defined in the Agreement). In certain circumstances, future distributions could result in Unit receiving distributions that are disproportionately lower than its ownership percentage. Circumstances that could result in Unit receiving less than a proportionate share of future distributions include, but may not be limited to, Unit not fulfilling the drilling commitment described in Note 14 – Commitments and Contingencies or a cumulative return to SP Investor Holdings, LLC of less than the 7% Liquidation IRR Hurdle provided for SP Investor Holdings, LLC in the Agreement. Generally, the 7% Liquidation IRR Hurdle calculation requires cumulative distributions to SP Investor Holdings, LLC in excess of its original $300.0 million investment sufficient to provide SP Investor Holdings, LLC a 7% IRR on its capital contributions to Superior before any liquidation distribution is made to Unit. After the fifth anniversary of the effective date of the sale, either owner may force a sale of Superior to a third-party or a liquidation of Superior's assets.

Effective at emergence from the Chapter 11 Cases, we record our share of earnings and losses from Superior using the HLBV method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if Superior were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our unaudited condensed consolidated statements of operations. On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements.

Under the guidance in ASC 810, Consolidation, we have determined that Superior is a VIE. The two variable interests applicable to Unit include the 50% equity investment in Superior and the MSA. The MSA gives us the power to direct the activities that most significantly affect Superior's operating performance. The MSA is a separate variable interest. Under the MSA, Unit has the power to direct Superior’s most significant activities; reciprocally the equity investors lack the power to direct the activities that most affect the entity’s economic performance. Because of this, Unit is considered the primary beneficiary. There have been no changes to the primary beneficiary during the quarter ended March 31, 2021.

As the primary beneficiary of this VIE, we consolidate in our financial statements the financial position, results of operations, and cash flows of this VIE. All intercompany balances and transactions between us and the VIE are eliminated in our consolidated financial statements. Cash distributions of income, net of agreed on expenses, and estimated expenses are allocated to the equity owners as specified in the relevant agreements.

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The amounts below reflect the eliminations of intercompany transactions and balances consistent with the presentation in the Unaudited Condensed Consolidated Balance Sheets.


	March 31, 2021		December 31, 2020
	(In thousands)

Current assets:
Cash and cash equivalents	$	24,687	$	11,642
Accounts receivable	25,890		27,427
Prepaid expenses and other	5,157		6,746
Total current assets	55,734		45,815
Property and equipment:
Gas gathering and processing equipment	252,463		251,403
Transportation equipment	1,822		1,748
	254,285		253,151
Less accumulated depreciation, depletion, amortization, and impairment	18,673		10,466
Net property and equipment	235,612		242,685
Right of use asset	2,384		2,823
Other assets	1,663		2,309
Total assets	$	295,393	$	293,632

Current liabilities:
Accounts payable	$	20,200	$	17,045
Accrued liabilities	3,164		3,777
Current operating lease liability	1,771		1,762
Current portion of other long-term liabilities	4,481		5,799
Total current liabilities	29,616		28,383

Operating lease liability	566		1,013
Other long-term liabilities	1,130		1,589
Total liabilities	$	31,312	$	30,985

NOTE 16 – INDUSTRY SEGMENT INFORMATION

We have three main business segments offering different products and services within the energy industry:

•Oil and natural gas,

•Contract drilling, and

•Mid-stream

Our oil and natural gas segment is engaged in the acquisition, development, and production of oil, NGLs, and natural gas properties. The contract drilling segment is engaged in the land contract drilling of oil and natural gas wells and the mid-stream segment is engaged in the buying, selling, gathering, processing, and treating of natural gas and NGLs.

We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization, and impairment. We have no oil and natural gas production outside the United States.

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The following tables provide certain information about the operations of each of our segments:


	Successor
	Three Months Ended March 31, 2021
	Oil and Natural Gas		Contract Drilling		Mid-stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	55,025	$	—	$	—	$	—	$	(1)	$	55,024
Contract drilling	—		15,674		—		—		—		15,674
Gas gathering and processing	—		—		59,610		—		(9,411)		50,199
Total revenues	55,025		15,674		59,610		—		(9,412)		120,897
Expenses:
Operating costs:
Oil and natural gas	19,993		—		—		—		(844)		19,149
Contract drilling	—		11,871		—		—		—		11,871
Gas gathering and processing	—		—		49,111		—		(8,568)		40,543
Total operating costs	19,993		11,871		49,111		—		(9,412)		71,563
Depreciation, depletion, and amortization	7,655		1,575		8,032		249		—		17,511
Total expenses	27,648		13,446		57,143		249		(9,412)		89,074
General and administrative	—		—		—		6,289		—		6,289
(Gain) loss on disposition of assets	(19)		(529)		75		1		—		(472)
Income (loss) from operations	27,396		2,757		2,392		(6,539)		—		26,006
Loss on derivatives	—		—		—		(22,831)		—		(22,831)
Interest, net	—		—		(1,057)		(1,649)		—		(2,706)
Reorganization items, net	—		—		—		(1,136)		—		(1,136)
Other	57		5		12		2		—		76
Income (loss) before income taxes	$	27,453	$	2,762	$	1,347	$	(32,153)	$	—	$	(591)

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1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

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	Predecessor
	Three Months Ended March 31, 2020
	Oil and Natural Gas		Contract Drilling		Mid-stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	48,524	$	—	$	—	$	—	$	(2)	$	48,522
Contract drilling	—		36,632		—		—		—		36,632
Gas gathering and processing	—		—		42,680		—		(5,458)		37,222
Total revenues	48,524		36,632		42,680		—		(5,460)		122,376
Expenses:
Operating costs:
Oil and natural gas	31,415		—		—		—		(752)		30,663
Contract drilling	—		25,449		—		—		—		25,449
Gas gathering and processing	—		—		32,319		—		(4,708)		27,611
Total operating costs	31,415		25,449		32,319		—		(5,460)		83,723
Depreciation, depletion, and amortization	36,728		11,745		12,273		871		—		61,617
Impairments	267,836		410,126		63,962		—		—		741,924
Total expenses	335,979		447,320		108,554		871		(5,460)		887,264
Loss on abandonment of assets	17,554		—		—		—		—		17,554
General and administrative	—		—		—		11,553		—		11,553
(Gain) loss on disposition of assets	(13)		409		(6)		—		—		390
Loss from operations	(304,996)		(411,097)		(65,868)		(12,424)		—		(794,385)
Gain on derivatives	—		—		—		483		—		483
Interest, net	—		—		(518)		(12,739)		—		(13,257)
Other	18		17		18		7		—		60
Loss before income taxes	$	(304,978)	$	(411,080)	$	(66,368)	$	(24,673)	—		$	(807,099)

_______________________

1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

NOTE 17 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Notes of the Predecessor company were registered securities until they were cancelled on the Effective Date. As a result, we are required to present the following condensed consolidating financial information for the Predecessor Periods under to Rule 3-10 of the SEC's Regulation S-X, Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered. Our Successor Exit credit agreement is not a registered security. Therefore, the presentation of condensed consolidating financial information is not required for the Successor Period.

For the following footnote:

•we are called "Parent",

•the direct subsidiaries are 100% owned by the Parent and the guarantee is full and unconditional and joint and several and called "Combined Guarantor Subsidiaries", and

•Superior and its subsidiaries and the Operator are called "Non-Guarantor Subsidiaries."

The following unaudited supplemental condensed consolidating financial information reflects the Parent's separate accounts, the combined accounts of the Combined Guarantor Subsidiaries', the combined accounts of the Non-Guarantor Subsidiaries', the combined consolidating adjustments and eliminations, and the Parent's consolidated amounts for the periods indicated.

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Condensed Consolidating Statements of Operations (Unaudited)


	Predecessor
	Three Months Ended March 31, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	85,154	$	42,680	$	(5,458)	$	122,376
Expenses:
Operating costs	—		56,864		32,317		(5,458)		83,723
Depreciation, depletion, and amortization	871		48,473		12,273		—		61,617
Impairments	—		677,962		63,962		—		741,924
Loss on abandonment of assets	—		17,554		—		—		17,554
General and administrative	—		11,553		—		—		11,553
(Gain) loss on disposition of assets	—		396		(6)		—		390
Total operating costs	871		812,802		108,546		(5,458)		916,761
Loss from operations	(871)		(727,648)		(65,866)		—		(794,385)
Interest, net	(12,739)		—		(518)		—		(13,257)
Gain on derivatives	483		—		—		—		483
Other, net	7		35		18		—		60
Loss before income taxes	(13,120)		(727,613)		(66,366)		—		(807,099)
Income tax benefit	—		(3,425)		—		—		(3,425)
Equity in net earnings from investment in subsidiaries, net of taxes	(790,554)		—		—		790,554		—
Net loss	(803,674)		(724,188)		(66,366)		790,554		(803,674)
Less: net loss attributable to non-controlling interest	(33,180)		—		(33,180)		33,180		(33,180)
Net loss attributable to Unit Corporation	$	(770,494)	$	(724,188)	$	(33,186)	$	757,374	$	(770,494)

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Condensed Consolidating Statements of Cash Flows (Unaudited)


	Predecessor
	Three Months Ended March 31, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(66,578)	$	86,663	$	9,827	$	—	$	29,912
INVESTING ACTIVITIES:
Capital expenditures	(421)		(13,051)		(4,056)		—		(17,528)
Producing properties and other acquisitions	—		(210)		—		—		(210)
Proceeds from disposition of assets	—		1,700		51		—		1,751
Net cash used in investing activities	(421)		(11,561)		(4,005)		—		(15,987)
FINANCING ACTIVITIES:
Borrowings under credit agreement	39,300		—		32,100		—		71,400
Payments under credit agreement	(23,500)		—		(11,600)		—		(35,100)
Intercompany borrowings (advances), net	75,016		(75,089)		73		—		—
Net payments on finance leases	—		—		(1,026)		—		(1,026)
Employee taxes paid by withholding shares	(43)		—		—		—		(43)
Bank overdrafts	(7,269)		—		(1,464)		—		(8,733)
Net cash provided by (used in) financing activities	83,504		(75,089)		18,083		—		26,498
Net increase in cash and cash equivalents	16,505		13		23,905		—		40,423
Cash and cash equivalents, beginning of period	503		68		—		—		571
Cash and cash equivalents, end of period	$	17,008	$	81	$	23,905	$	—	$	40,994

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion should be read together with the condensed consolidated financial statements included in Item 1 of Part I of this report and in Item 8 of our 2020 Form 10-K filed with the SEC on March 31, 2021.

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

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

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

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

In addition to the companies identified above, our corporate headquarters is owned by our wholly owned subsidiary 8200 Unit Drive, L.L.C. (8200 Unit).

Our strategy is focused on value accretion through generation of free cash flows, repayment of debt, and selective investment in each business segment.

In our oil and natural gas segment, we are optimizing production and converting non-producing reserves to producing, with no exploratory drilling activities. We also plan to divest non-core properties and use those proceeds along with free cash flows to acquire producing properties in our core areas.

In our contract drilling segment, we are focused on utilization of our BOSS drilling rigs. 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. References to "Successor Period" relate to the results of operations for the period January 1, 2021 through March 31, 2021 and references to "Predecessor Period" refer to the results of operations for the period January 1, 2020 through March 31, 2020.

Recent Developments

COVID-19 Pandemic and Commodity Price Environment

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.

We are continuously monitoring the current and potential impacts of the COVID-19 pandemic on our business. This includes how it has and may continue to impact our operations, financial results, liquidity, customers, employees, and vendors. 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:

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

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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 its pro rata share of seven-year warrants (Warrants) to purchase an aggregate of 12.5% of the shares of New Common Stock, at an aggregate exercise price equal to the $650.0 million principal amount of the 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. On February 11, 2021, we issued 42,511 Warrants to certain holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares through direct registration with the company’s transfer agent (Direct Registration). We expect to issue approximately 37,000 additional 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. Under the Plan, additional Warrants will be issued in book-entry form through the facilities of the DTC, and each holder owning shares of Old Common Stock through Direct Registration must provide that holder’s brokerage account information to the company to receive such holder’s distribution of Warrants. Holders of shares of the Old Common Stock that owned shares through Direct Registration should contact Prime Clerk, LLC at (877) 720-6581 (Toll Free) or (646) 979-4412 (Local) to obtain the forms necessary to receive their distribution. Any distribution not made will be deemed forfeited at the first anniversary of the Effective Date.

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 rates we receive for those drilling rigs; and

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

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		% Change
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
	(In thousands except percentages)
Net cash provided by operating activities	30,304		29,912		1	%
Net cash provided by (used in) investing activities	2,428		(15,987)		115	%
Net cash provided by (used in) financing activities	(20,258)		26,498		(176)	%
Net increase in cash, restricted cash and cash equivalents	$	12,474	$	40,423

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 in the first three months of 2021 increased by $0.4 million as compared to the first three months of 2020. The increase resulted from 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.

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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 any future capital budgets would be focused on development or acquisitions of producing oil and gas properties, and not exploration.

Net cash provided by (used in) investing activities decreased by $18.4 million for the first three months of 2021 compared to the first three months of 2020. The change was due primarily to a decrease in capital expenditures resulting from a decrease in number of wells drilled, along with a decrease in oil and gas property acquisitions, which was partially offset by an increase in proceeds received from the disposition of assets.

Cash Flows from Financing Activities

Net cash provided by (used in) financing activities decreased by $46.8 million for the first three months of 2021 compared to the first three months of 2020. The decrease was primarily due to decreases in both the net borrowings under our credit agreements and in bank overdrafts.

At March 31, 2021, we had unrestricted cash and cash equivalents totaling $25.2 million and had borrowed $79.0 million of the amounts available under the Exit credit agreement. We did not have any outstanding borrowings under our Superior credit agreement.

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


	Successor		Predecessor
	2021		2020
	(In thousands)
Working capital	$	6,096	$	(781,278)
Current portion of long-term debt (1)	$	800	$	771,283
Long-term debt	$	78,200	$	37,000
Shareholders’ equity attributable to Unit Corporation	$	177,359	$	85,878

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1.Current portion of long-term debt is net of unamortized discount and debt issuance costs for the Predecessor Period.

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 $6.1 million and negative working capital of $781.3 million as of March 31, 2021 and 2020, respectively. The increase in working capital is primarily due to the settlement of the liabilities subject to compromise, an increase in accounts receivable and lower accounts payable and accrued liabilities. At March 31, 2020, the negative working capital was primarily due to the springing maturity of the Unit credit agreement and the Notes and the determination to treat the borrowings as current liabilities. Both the Superior credit agreement and the Exit credit agreement are used for working capital. The effect of our derivative contracts decreased working capital by $14.0 million as of March 31, 2021 and increased working capital by $0.7 million as of March 31, 2020.

Our Credit Agreements

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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.

At March 31, 2021, we had $0.8 million and $78.2 million outstanding current and long-term borrowings, respectively, under the Exit credit agreement. During the period ended March 31, 2021, the company repaid $20.0 million of borrowings under the RBL Facility with cash generated from operations as well as from proceeds from divestitures of non-core assets.

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.

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. We participated in the completion of one gross well (0.17 net wells) drilled by other operators in the first three months of 2021 compared to 14 gross wells (3.07 net wells) drilled by Unit and other operators in which we participated in the first three months of 2020.

Capital expenditures for oil and gas properties on the full cost method for the first three months of 2021 by this segment, totaled $2.6 million. Capital expenditures for the first three months of 2020, excluding $0.2 million for acquisitions and a $3.4 million reduction in the ARO liability, totaled $7.7 million.

For 2021, we primarily plan to focus our capital expenditures on development of proved properties and acquisition of proved and producing properties.

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 will not result in a significant alteration of the full cost pool and therefore, no gain or loss will be recognized.

We sold $1.7 million of non-core oil and natural gas assets, net of related expenses, during the first three months of 2021, compared to $0.6 million during the first three months of 2020. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.

Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. For 2021, capital expenditures are expected to primarily be for maintenance capital on operating drilling rigs. We also plan to pursue the disposal or sale of our non-core, idle drilling rig fleet. We have spent $0.1 million for capital expenditures during the first three months of 2021, compared to $2.2 million for capital expenditures during the first three months of 2020.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. During the first three months of 2021, our mid-stream segment incurred $1.1 million in capital expenditures as compared to $5.0 million in the first three months of 2020. For 2021, our estimated capital expenditures will be approximately $15.0 million which we expect to be primarily for the maintenance and operation of our assets and connection of new wells.

Derivative Activities

Periodically we enter into derivative transactions locking in the prices to be received for a portion of our oil, NGLs, and natural gas production.

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Commodity Derivatives. Our commodity derivatives are intended to reduce our exposure to price volatility and manage price risks. Our decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our view of current and future market conditions. At March 31, 2021, based on our first quarter 2021 average daily production, the approximated percentages of our production under derivative contracts are as follows:


	2021		2022		2023
Daily oil production	74	%	51	%	29	%
Daily natural gas production	61	%	50	%	27	%

The use of derivative transactions carries with it the risk that the counterparties may not be able to meet their financial obligations under the transactions. Based on our March 31, 2021 evaluation, we believe the risk of non-performance by our counterparties is not material. At March 31, 2021, the fair values of the net liabilities we had with each of the counterparties to our commodity derivative transactions are as follows:


	March 31, 2021
	(In thousands)
Bank of Oklahoma	$	(24,857)
Bank of Montreal	(376)
Total net liabilities	$	(25,233)

Below is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the periods indicated:


	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
	(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $(3,304) and $551, respectively	$	(22,831)	$	483
	$	(22,831)	$	483

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Results of Operations

Three Months Ended March 31, 2021 versus Three Months Ended March 31, 2020

Provided below is a comparison of selected operating and financial data:


	Successor			Predecessor			Percent Change (1)
	Three Months Ended March 31, 2021			Three Months Ended March 31, 2020
	(In thousands unless otherwise specified)
Total revenue	$	120,897		$	122,376		(1)	%
Net loss	$	(591)		$	(803,674)		100	%
Net income (loss) attributable to non-controlling interest	$	1,346		$	(33,180)		104	%
Net loss attributable to Unit Corporation	$	(1,937)		$	(770,494)		100	%

Oil and Natural Gas:
Revenue	$	55,024		$	48,522		13	%
Operating costs	$	19,149		$	30,663		(38)	%


Average oil price (Bbl)	$	47.29		$	44.92		5	%
Average oil price per barrel received excluding derivatives	$	56.12		$	44.92		25	%
Average NGLs price (Bbl)	$	17.96		$	3.27		NM
Average NGLs price per barrel received excluding derivatives	$	17.96		$	3.27		NM
Average natural gas price (Mcf)	$	2.77		$	1.23		125	%
Average natural gas price per mcf received excluding derivatives	$	2.72		$	1.18		131	%
Oil production (MBbls)	413			674			(39)	%
NGLs production (MBbls)	641			965			(34)	%
Natural gas production (MMcf)	7,403			10,802			(31)	%


Contract Drilling:
Revenue	$	15,674		$	36,632		(57)	%
Operating costs	$	11,871		25,449			(53)	%




Average number of drilling rigs in use	9.4			18.7			(50)	%
Total drilling rigs available for use at the end of the period	21			58			(64)	%
Average dayrate on daywork contracts	$	18,127		$	19,535		(7)	%

Mid-Stream:
Revenue	$	50,199		$	37,222		35	%
Operating costs	$	40,543		$	27,611		47	%


Gas gathered--Mcf/day	299,591			389,243			(23)	%
Gas processed--Mcf/day	121,138			166,331			(27)	%
Gas liquids sold--gallons/day	409,285			527,673			(22)	%
Number of natural gas gathering systems	17			19			(11)	%
Number of processing plants	11			11			—	%

Corporate and Other:

General and administrative expense	$	6,289		$	11,553		(46)	%


Other income (expense):

Interest expense, net	$	(2,706)		$	(13,257)		(80)	%
Reorganization costs, net	$	(1,136)		$	—		—	%
Gain (loss) on derivatives	$	(22,831)		$	483		NM

Income tax benefit	$	—		$	(3,425)		100	%
Average interest rate	6.8		%	6.3		%	8	%
Average long-term debt outstanding	$	93,227		$	761,502		(88)	%

_________________________

1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

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Oil and Natural Gas

Oil and natural gas revenues increased $6.5 million or 13% in the first three months of 2021 as compared to the first three months of 2020 primarily due to higher commodity prices partially offset by lower volumes. The decline in volumes was due to normal well production declines which have not been offset by new drilling or acquisitions for new production.

Oil and natural gas operating costs decreased $11.5 million or 38% between the comparative first three months of 2021 and 2020 primarily due to lower LOE, and gross production taxes partially offset by higher salt water disposal operating expense.

Contract Drilling

Drilling revenues decreased $21.0 million or 57% in the first three months of 2021 versus the first three months of 2020. The decrease was due primarily to a 50% decrease in the average number of drilling rigs in use and a 7% decrease in the average dayrate. Average drilling rig utilization decreased from 18.7 drilling rigs in the first three months of 2020 to 9.4 drilling rigs in the first three months of 2021. The decline in our average drilling rig utilization is a result of the impact of reduced commodity prices.

Drilling operating costs decreased $13.6 million or 53% between the comparative first three months of 2021 and 2020. The decrease was due primarily to less drilling rigs operating.

During the period, management reduced the number of drilling rigs available for use to 21 compared to 58 at December 31, 2020. The decrease corresponds with the company's strategy to focus on the utilization of our 14 BOSS rigs and certain SCR rigs that are either currently under contract or candidates for future upgrades. Of the 21 rigs available for use, 10 are currently working, seven are actively being marketed, and the remaining four will be considered for upgrade and marketing as future conditions warrant. The company will continue its efforts to sell or scrap those other rigs that are not considered part of our available fleet.

Mid-Stream

Our mid-stream revenues increased $13.0 million or 35% in the first three months of 2021 as compared to the first three months of 2020 due primarily to higher prices partially offset by lower volumes. Gas processed volumes per day decreased 27% between the comparative periods primarily due to declining volumes, lower offload volume from producers, and fewer new wells connected to our producing systems. We also experienced lower volumes due to the February winter storm. Gas gathered volumes per day decreased 23% between the comparative periods also due to declining volumes, lower offload volume from producers, and fewer new wells connected to our producing systems.

Operating costs increased $12.9 million or 47% in the first three months of 2021 compared to the first three months of 2020 primarily due to higher purchase prices partially offset by lower purchase volumes.

General and Administrative

Corporate general and administrative expenses decreased $5.3 million or 46% in the first three months of 2021 as compared to the first three months of 2020 primarily due to lower consulting and legal fees paid prior to filing for bankruptcy as well as reduced employee headcount.

Other Income (Expense)

Interest expense decreased $10.6 million between the comparative first three months of 2021 and 2020 due to reduced borrowings. Our average interest rate increased from 6.3% in the first three months of 2020 to 6.8% in the first three months of 2021 and our average debt outstanding decreased $668.3 million in the first three months of 2021 compared to the first three months of 2020 primarily due to the Notes being settled with the Plan.

Reorganization Items, Net

Reorganization items, net represent any of the expenses, gains, and losses incurred subsequent to and as a direct result of the Chapter 11 proceedings.

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Gain (Loss) on Derivatives

Gain (loss) on derivatives decreased by $23.3 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Income Tax Benefit

We did not record an income tax benefit in the first three months of 2021 compared to $3.4 million in the first three months of 2020 due to the company's full valuation allowance against our net deferred tax asset. Our effective tax rate was 0.00% for the first three months of 2021 compared to 0.42% for the first three months of 2020 due to the adjustment to our total valuation allowance for the income tax benefit that was generated during the period. We paid no income taxes in the first three months of 2021.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

Our operations are exposed to market risks primarily because of changes in commodity prices and interest rates.

Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas production. These prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our NGLs and natural gas production. Historically, these prices have fluctuated and we expect this to continue. The prices for oil, NGLs, and natural gas also affect the demand for our drilling rigs and the amount we can charge for the use of our drilling rigs. Based on our first three months 2021 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of hedging, would result in a corresponding $250,000 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 hedging, would have a $132,000 per month ($1.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of hedging, would have a $209,000 per month ($2.5 million annualized) change in our pre-tax operating cash flow.

We use derivative transactions to manage the risk associated with price volatility. Our decisions regarding the amount and prices at which we choose to enter into a contract for certain of our products is based, in part, on our view of current and future market conditions. The transactions we use include financial price swaps under which we will receive a fixed price for our production and pay a variable market price to the contract counterparty. We do not hold or issue derivative instruments for speculative trading purposes.

At March 31, 2021, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Apr'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$(0.215)

NGPL TEXOK

Apr'21 - Oct'21

Natural gas - swap

50,000 MMBtu/day

$2.818

IF - NYMEX (HH)

Nov'21 - Dec'21

Natural gas - swap

45,000 MMBtu/day

$2.900

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - swap

5,000 MMBtu/day

$2.605

IF - NYMEX (HH)

Jan'23 - Dec'23

Natural gas - swap

22,000 MMBtu/day

$2.456

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - collar

35,000 MMBtu/day

$2.50 - $2.68

IF - NYMEX (HH)

Apr'21 - Dec'21

Crude oil - swap

3,373 Bbl/day

$46.16

WTI - NYMEX

Jan'22 - Dec'22

Crude oil - swap

2,300 Bbl/day

$42.25

WTI - NYMEX

Jan'23 - Dec'23

Crude oil - swap

1,300 Bbl/day

$43.60

WTI - NYMEX

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our Exit credit agreement and Superior credit agreement. Borrowings under our Exit credit agreement and Superior credit agreement carry variable interest rates. A 1% increase in the interest rates on the outstanding borrowings under these facilities at March 31, 2021 would reduce our annual pre-tax cash flow by approximately $0.1 million. For further information, see Note 8 – Long-Term Debt and Other Long-Term Liabilities.

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Item 4. Controls and Procedures

Our management, including our Chief Executive Officer (CEO) and Interim Chief Financial Officer (Interim CFO), does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) (Disclosure Controls) or our internal control over financial reporting (ICFR) (as defined in Rules 13a - 15(f) and 15d - 15(f) of the Exchange Act) will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part on certain assumptions about the likelihood of future events, and there is no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to an error or fraud may occur and not be detected. We monitor our Disclosure Controls and ICFR and make modifications as necessary; our intent in this regard is that the Disclosure Controls and ICFR will be modified as systems change, and conditions warrant.

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our CEO and Interim CFO, of the effectiveness of the design and operation of our disclosure controls and procedures under Exchange Act Rule 13a-15. Based on that evaluation, our CEO and Interim CFO concluded that our disclosure controls and procedures were not effective as of March 31, 2021 due to a material weakness in ICFR described below.

Material Weakness in ICFR. A material weakness is a deficiency, or combination of deficiencies, in ICFR resulting in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

As previously disclosed in our Quarterly Report on Form 10-Q for the period ended June 30, 2020, in preparing our interim financial statements for the quarterly period ended June 30, 2020, we determined that a material weakness related to management review controls over complex accounting matters was present. Key elements of effectively designed management review controls include the establishment of documentation standards for process owners to document the substance of their work related to critical accounting estimates, complex accounting matters, and non-routine transactions. Effectively designed management review controls must also have an established process that allows senior accounting personnel having the appropriate knowledge of the subject matter to have enough time to perform effective reviews. Necessary elements for effectively designed management review controls were either not present at June 30, 2020 or not present for a sufficient period of time in order to conclude our disclosure controls and procedures were effective at June 30, 2020. This continued to be the case at March 31, 2021.

Plan for Remediation of the Material Weakness. We continue to address the underlying cause of the material weakness, including a redesign of certain management review controls related to complex accounting matters, the establishment of documentation standards, assessing the structure of the accounting organization, providing additional training for employees responsible for performing important management review controls, and supplementing internal resources with external expertise when appropriate.

We have also hired new personnel in key positions and continue to evaluate the need for additional personnel to further enhance the overall control environment.

Our management believes the measures described above will eventually remediate this material weakness. As management continues to evaluate and improve internal control over financial reporting, we may decide to take additional measures to address this control deficiency or determine to modify, or in appropriate circumstances not to complete, certain of the remediation measures. However, this material weakness will not be considered remediated until the applicable remedial controls operate for a sufficient period of time and management has tested the effectiveness of those controls.

Changes in Internal Controls. There were no other changes in our ICFR during the quarter ended March 31, 2021, that materially affected our ICFR or are reasonably likely to materially affect it, as defined in Rule 13a – 15(f) under the Exchange Act.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For further information about the outstanding legal proceedings, please see Note 14 – Commitments And Contingencies.

Item 1A. Risk Factors

In addition to the other information set forth in this quarterly report, you should carefully consider the factors discussed below, if any, and in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2020, which could materially affect our business, financial condition, or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, and/or operating results.

There have been no material changes to the risk factors disclosed in Item 1A in our Form 10-K for the year ended December 31, 2020.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not Applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

Exhibits:


10.1			First Amendment to Amended and Restated Credit Agreement dated April 6, 2021

10.2			Form of Restricted Stock Unit (RSU) Grant Notice and Award Agreement

31.1			Certification of Chief Executive Officer under Rule 13a – 14(a) of the Exchange Act.

31.2			Certification of Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act.

32			Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act and 18 U.S.C. Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS			XBRL Instance Document.

101.SCH			XBRL Taxonomy Extension Schema Document.

101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF			XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB			XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		Unit Corporation

Date:	May 12, 2021	By: /s/ Philip B. Smith
		PHILIP B. SMITH
		President and Chief Executive Officer

Date:	May 12, 2021	By: /s/ Thomas D. Sell
		THOMAS D. SELL
		Interim Chief Financial Officer