UNIT CORP - Quarter Report: 2021 June (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 June 30, 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 Section 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.

Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒

Smaller reporting company ☒ Emerging growth company ☐

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

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

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

As of August 16, 2021, 11,210,545 shares of the issuer's common stock were outstanding.

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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 s 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 Upo n 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 address 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 and 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 3 Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk.”

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	June 30, 2021		December 31, 2020
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	6,989	$	12,145
Restricted cash	—		569
Accounts receivable, net of allowance for credit losses of $4,265 and $3,783 at June 30, 2021 and December 31, 2020, respectively	63,879		57,846



Current income tax receivable	34		1,150

Prepaid expenses and other	6,212		11,212
Total current assets	77,114		82,922
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties	233,004		238,581
Unproved properties not being amortized	487		1,591
Drilling equipment	64,056		63,687
Gas gathering and processing equipment	255,338		251,404
Land and building	32,635		32,635
Transportation equipment	3,486		3,130
Other	8,935		9,961
	597,941		600,989
Less accumulated depreciation, depletion, amortization, and impairment	88,416		54,189
Net property and equipment	509,525		546,800


Right of use asset (Note 14)	6,406		5,592
Other assets	16,111		14,389
Total assets (1)	$	609,156	$	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


	June 30, 2021		December 31, 2020
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	38,081	$	37,368
Accrued liabilities (Note 8)	23,748		25,204
Current operating lease liability (Note 14)	3,515		4,075
Current portion of long-term debt (Note 9)	—		600
Current derivative liabilities (Note 12)	37,960		1,047
Warrant liability (Note 13)	4,459		885
Current portion of other long-term liabilities (Note 9)	7,551		11,168
Total current liabilities	115,314		80,347
Long-term debt (Note 9)	35,000		98,400
Non-current derivative liabilities (Note 12)	23,270		4,659
Operating lease liability (Note 14)	2,856		1,445
Other long-term liabilities (Note 9)	38,871		39,259
Commitments and contingencies (Note 15)
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 and 11,400,000 outstanding at June 30, 2021 and 12,000,000 shares issued and outstanding at December 31, 2020	120		120
Treasury stock	(9,048)		—
Capital in excess of par value	197,561		197,242

Retained deficit	(33,071)		(18,140)
Total shareholders’ equity attributable to Unit Corporation	155,562		179,222
Non-controlling interests in consolidated subsidiaries	238,283		246,371
Total shareholders' equity	393,845		425,593
Total liabilities(1) and shareholders’ equity	$	609,156	$	649,703

_______________________

(1)Unit Corporation's consolidated total assets as of June 30, 2021 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $37.4 million and $237.0 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of June 30, 2021 include total current and long-term liabilities of the VIE of $28.7 million and $3.4 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 16 – 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		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	41,970	$	26,956	$	96,994	$	75,478
Contract drilling	18,061		29,202		33,735		65,834
Gas gathering and processing	74,026		32,849		124,225		70,071
Total revenues	134,057		89,007		254,954		211,383
Expenses:
Operating costs:
Oil and natural gas	15,487		71,540		34,636		102,203
Contract drilling	14,080		20,951		25,951		46,400
Gas gathering and processing	45,056		22,612		84,719		50,223
Total operating costs	74,623		115,103		145,306		198,826
Depreciation, depletion, and amortization	16,364		35,960		33,875		97,577
Impairments (Note 3)	—		109,318		—		851,242
Loss on abandonment of assets (Note 3)	—		—		—		17,554
General and administrative	5,751		25,814		12,920		37,367
(Gain) loss on disposition of assets	(1,710)		877		(2,182)		1,267
Total operating expenses	95,028		287,072		189,919		1,203,833
Income (loss) from operations	39,029		(198,065)		65,035		(992,450)
Other income (expense):
Interest, net (excludes interest expense of $5.4 million on senior subordinated notes subject to compromise, for the three and six months ended June 30, 2020)	(487)		(7,608)		(3,193)		(20,865)
Write-off of debt issuance costs	—		(2,426)		—		(2,426)
Loss on derivatives (Note 12)	(42,400)		(6,937)		(65,231)		(6,454)
Loss on change in fair value of warrants (Note 13)	(3,574)		—		(3,574)		—
Reorganization items, net	(1,852)		(7,027)		(2,988)		(7,027)
Other, net	(831)		43		(755)		103
Total other income (expense)	(49,144)		(23,955)		(75,741)		(36,669)
Loss before income taxes	(10,115)		(222,020)		(10,706)		(1,029,119)
Income tax benefit:
Current	—		—		—		(917)
Deferred	—		(6,455)		—		(8,963)
Total income taxes	—		(6,455)		—		(9,880)
Net loss	(10,115)		(215,565)		(10,706)		(1,019,239)
Net income (loss) attributable to non-controlling interest	2,879		84		4,225		(33,096)
Net loss attributable to Unit Corporation	$	(12,994)	$	(215,649)	$	(14,931)	$	(986,143)
Net loss attributable to Unit Corporation per common share (Note 7):
Basic	$	(1.09)	$	(4.03)	$	(1.25)	$	(18.50)
Diluted	$	(1.09)	$	(4.03)	$	(1.25)	$	(18.50)

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 June 30, 2021
	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Treasury Stock		Capital in Excess of Par Value		Retained Earnings (Deficit)		Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, March 31, 2021 (Successor)	$	120	$	—	$	197,316	$	(20,077)	$	247,733	$	425,092
Net income (loss)	—		—		—		(12,994)		2,879		(10,115)

Activity in stock-based compensation plans	—		—		245		—		15		260
Distributions to non-controlling interests	—		—		—		—		(12,344)		(12,344)
Repurchase of common stock	—		(9,048)		—		—		—		(9,048)
Balances, June 30, 2021 (Successor)	$	120	$	(9,048)	$	197,561	$	(33,071)	$	238,283	$	393,845


	Six Months Ended June 30, 2021
	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Treasury 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)	—				—		(14,931)		4,225		(10,706)

Activity in stock-based compensation plans	—		—		319		—		31		350
Distributions to non-controlling interests	—		—		—		—		(12,344)		(12,344)
Repurchase of common stock	—		(9,048)		—		—		—		(9,048)
Balances, June 30, 2021 (Successor)	$	120	$	(9,048)	$	197,561	$	(33,071)	$	238,283	$	393,845

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) - CONTINUED


	Three Months Ended June 30, 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, March 31, 2020 (Predecessor)	$	10,694	$	646,543	$	(571,359)	$	168,608	$	254,486
Net income (loss)	—		—		(215,649)		84		(215,565)


Activity in stock-based compensation plans	10		1,585		—		16		1,611
Balances, June 30, 2020 (Predecessor)	$	10,704	$	648,128	$	(787,008)	$	168,708	$	40,532


	Six Months Ended June 30, 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	—		—		(986,143)		(33,096)		(1,019,239)



Activity in stock-based compensation plans	113		3,976		—		47		4,136
Balances, June 30, 2020 (Predecessor)	$	10,704	$	648,128	$	(787,008)	$	168,708	$	40,532

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
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(In thousands)
OPERATING ACTIVITIES:
Net loss	$	(10,706)	$	(1,019,239)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	33,875		97,577
Impairments (Note 3)	—		851,242
Loss on abandonment of assets (Note 3)	—		17,554
Amortization of debt issuance costs and debt discount	—		1,079
Loss on derivatives (Note 12)	65,231		6,454
Cash payments on derivatives settled (Note 12)	(9,707)		(691)
Loss on change in fair value of warrants (Note 13)	3,574		—
(Gain) loss on disposition of assets	(2,182)		1,267
Write-off of debt issuance costs	—		2,426
Deferred tax benefit	—		(8,963)
Stock-based compensation plans	350		4,179
Credit loss expense	482		1,923
ARO liability accretion (Note 10)	931		1,169
Contract assets and liabilities, net (Note 4)	1,584		1,790
Capitalized contract fulfillment costs, net	26		—
Noncash reorganization items	433		7,027
Other, net	(1,035)		11,493

Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(6,336)		26,587
Material and supplies	—		43
Prepaid expenses and other	2,536		(2,703)
Accounts payable	(2,279)		(22,876)
Accrued liabilities	(3,852)		48,244
Income taxes	1,116		906
Contract advances	(76)		(21)

Net cash provided by operating activities	73,965		26,467
INVESTING ACTIVITIES:
Capital expenditures	(7,673)		(23,804)
Producing properties and other acquisitions	—		(210)
Proceeds from disposition of property and equipment	15,278		4,497


Net cash provided by (used in) investing activities	7,605		(19,517)
FINANCING ACTIVITIES:
Borrowings under line of credit, including borrowings under DIP credit facility	3,900		79,400
Payments under line of credit	(67,900)		(38,100)
DIP financing costs	—		(990)

Net payments on finance leases	(3,216)		(2,061)
Employee taxes paid by withholding shares	—		(43)





Distributions to non-controlling interests	(12,344)		—
Repurchase of common stock	(9,048)		—
Bank overdrafts	1,313		(8,733)
Net cash provided by (used in) financing activities	(87,295)		29,473
Net increase (decrease) in cash, restricted cash and cash equivalents	(5,725)		36,423
Cash, restricted cash, and cash equivalents, beginning of period	12,714		571
Cash, restricted cash, and cash equivalents, end of period	$	6,989	$	36,994

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
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(In thousands)
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Interest paid	$	3,764	$	4,795
Income taxes	(1,116)		—
Reorganization items	2,554		—

Changes in accounts payable and accrued liabilities related to purchases of property and equipment	(3,318)		5,974
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	1,115		3,548
Non-cash trade of property 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 Pipeline Company, L.L.C. (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 not necessarily indicative of annual results. The company evaluates subsequent events through the date the financial statements are issued.

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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 Date) would not have a material impact to the unaudited condensed consolidated financial statements. This was reflected in our unaudited condensed consolidated balance sheet as of September 1, 2020. Accordingly, our unaudited condensed consolidated financial statements and notes after September 1, 2020, are not comparable to the unaudited 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, a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, (SP Investor) which qualifies as a Variable Interest Entity (VIE) under 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 16 – Variable Interest Entity Arrangements.

During second quarter 2021, management identified errors in our inter-segment eliminations presentation between oil and natural gas revenues and gas gathering and processing revenues as well as between gas gathering and processing operating costs and general and administrative expenses. The impacts of the errors were not material to any of our prior period financial statements and the current year impacts on the three months ended March 31, 2021 were corrected with a one-time adjustment in the three months ended June 30, 2021. As a result, during the three months ended June 30, 2021, oil and natural gas revenues were decreased by $8.6 million with a corresponding increase to gas gathering and processing revenues while general and administrative expenses were increased by $0.9 million with a corresponding decrease to gas gathering and processing operating costs.

Also during second quarter 2021, management identified separate errors in our prior period accrual of oil and natural gas revenues as well as oil and natural gas operating costs. The impacts of the errors were not material to any of our prior period financial statements and the errors were corrected with a one-time adjustment in the three months ended June 30, 2021. As a result, during the three months ended June 30, 2021, oil and natural gas revenues were increased by $3.9 million and oil and natural gas operating costs were decreased by $3.4 million.

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.

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Recent Accounting Pronouncements

Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging— Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The FASB issued ASU 2020-06 which simplifies the accounting for convertible instruments by removing certain accounting models which separate the embedded conversion features from the host contract for convertible instruments. The ASU further removes certain settlement conditions that are required for equity contracts to qualify for the derivative scope exception and simplifies the diluted earnings per share calculation in certain areas. The ASU is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. Early adoption is permitted. We are currently evaluating the potential impact on our financial statements.

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 GAAP 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 unaudited condensed 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 unaudited condensed 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 three and six months ended June 30, 2021.

During the three months ended March 31, 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 three months ended March 31, 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 three months ended March 31, 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. There were no additional triggering events identified during the three months ended June 30, 2020.

In addition to the impairment evaluations of our proved and unproved oil and gas properties in the three months ended March 31, 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 three months ended March 31, 2020. These amounts are reported in loss on abandonment of assets in our unaudited condensed consolidated statements of operations. There were no additional triggering events identified during the three months ended June 30, 2020.

Contract Drilling

There were no impairments recorded during the three and six months ended June 30, 2021.

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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 three months ended March 31, 2020. We also recorded an additional non-cash impairment charges of $3.0 million for other miscellaneous drilling equipment. These charges are included within impairments 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. There were no additional triggering events identified during the three months ended June 30, 2020.

We concluded that no impairment was needed on the BOSS drilling rigs asset group as of March 31, 2020 as the undiscounted cash flows exceeded the $242.5 million carrying value of the asset group 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. There were no additional triggering events identified during the three months ended June 30, 2020.

Mid-Stream

There were no impairments recorded during the three and six months ended June 30, 2021.

During the three months ended March 31, 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. We recorded non-cash impairment charges of $64.0 million based on the estimated fair value of the asset groups. These charges are included within impairments in our unaudited condensed consolidated statement of operations. There were no additional triggering events identified during the three months ended June 30, 2020.

NOTE 4 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream which is consistent with how we report our segment revenue (as reflected in Note 18 – 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 June 30, 2021, we had six contract drilling contracts with remaining terms ranging from two to seven months.

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.

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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 unaudited condensed consolidated balance sheets	June 30, 2021		December 31, 2020		Change
		(In thousands)
Assets
Current contract assets	Prepaid expenses and other	$	3,226	$	6,084	$	(2,858)
Non-current contract assets	Other assets	—		173		(173)
Total contract assets		$	3,226	$	6,257	$	(3,031)

Liabilities
Current contract liabilities	Current portion of other long-term liabilities	$	2,098	$	2,583	$	(485)
Non-current contract liabilities	Other long-term liabilities	626		1,589		(963)
Total contract liabilities		2,724		4,172		(1,448)
Contract assets (liabilities), net		$	502	$	2,085	$	(1,583)

Included below is the adjustment to demand fees from adopting ASC 606, Revenue from contracts with customers over the remaining term of the contracts as of June 30, 2021.


Contract	Remaining Term of Contract	2021		2022		2023 and beyond		Total Remaining Impact to Revenue
		(In thousands)
Demand fee contracts	4 - 16 months	$	(1,876)	$	1,374	$	—	$	(502)

NOTE 5 – DIVESTITURES

Oil and Natural Gas

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

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

We sold $4.4 million of other non-core oil and natural gas assets, net of related expenses, during the six months ended June 30, 2021, compared to $0.9 million during the six months ended June 30, 2020. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.

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Contract Drilling

We sold non-core contract drilling assets for proceeds of $3.9 million, net of related expenses, during the six months ended June 30, 2021, compared to proceeds of $2.8 million during the six months ended June 30, 2020. These proceeds resulted in net gains of $2.1 million during the six months ended June 30, 2021, compared to $0.1 million during the six months ended June 30, 2020.

Corporate and Other

The company entered into a purchase and sale agreement to which we agreed to sell our corporate headquarters building and land with an anticipated closing date during the third quarter of 2021. The agreement remains subject to customary closing conditions. If the transaction closes, we plan to enter a multi-year lease for a portion of the building and no material gain or loss is expected.

NOTE 6 – CAPITAL STOCK

On June 16, 2021, the company repurchased an aggregate of 600,000 shares of its common stock from the Lenders (as defined in Note 9 - Long-Term Debt and Other Long-Term Liabilities) which received these shares as an exit fee during the company’s reorganization. The Lenders were paid $15.00 per share for their respective shares, for an aggregate cash purchase price of $9.0 million. The cash purchase price and direct acquisition costs are reflected as treasury stock on the condensed consolidated balance sheets as of June 30, 2021.

In June 2021, the company's board of directors (the Board) authorized repurchasing up to $25.0 million of the company’s outstanding common stock. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. The company has no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice. As of June 30, 2021, no repurchases have been made under the share repurchase program.

NOTE 7 – LOSS PER SHARE

On the Effective Date, the company's shares outstanding immediately before the Effective Date were cancelled. Information related to the calculation of capital stock attributable to Unit Corporation is as follows:


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended June 30, 2021 (Successor)
Basic loss attributable to Unit Corporation per common share	$	(12,994)	11,901	$	(1.09)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(12,994)	11,901	$	(1.09)
For the three months ended June 30, 2020 (Predecessor)
Basic loss attributable to Unit Corporation per common share	$	(215,649)	53,503	$	(4.03)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(215,649)	53,503	$	(4.03)

Because of the net loss for the three months ended June 30, 2021, approximately 77,863 weighted average shares of restricted stock were antidilutive and were excluded from the earnings per share calculation above.

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The following table shows the number of stock options (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:


	Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020

Stock options	—		28,000
Average exercise price	$	—	$	52.24


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the six months ended June 30, 2021 (Successor)
Basic loss attributable to Unit Corporation per common share	$	(14,931)	11,950	$	(1.25)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(14,931)	11,950	$	(1.25)
For the six months ended June 30, 2020 (Predecessor)
Basic loss attributable to Unit Corporation per common share	$	(986,143)	53,317	$	(18.50)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(986,143)	53,317	$	(18.50)

Because of the net loss for the six months ended June 30, 2021, approximately 39,147 weighted average shares of restricted stock were antidilutive and were excluded from the earnings per share calculation above.

The following table shows the number of stock options (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:


	Successor		Predecessor
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020

Stock options	—		28,000
Average exercise price	$	—	$	52.24

NOTE 8 – ACCRUED LIABILITIES

Accrued liabilities consisted of:



	June 30, 2021		December 31, 2020
	(In thousands)
Employee costs	$	7,184	$	8,878
Lease operating expenses	3,686		6,405
Capital expenditures	5,500		3,461
Taxes	5,352		2,324
Interest payable	303		884
Legal settlement	—		2,070
Other	1,723		1,182
Total accrued liabilities	$	23,748	$	25,204

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NOTE 9 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

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


	June 30, 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 June 30, 2021 and December 31, 2020, respectively	$	—	$	600
Long-term debt:
Exit credit agreement with an average interest rate of 6.7% and 6.6% at June 30, 2021 and December 31, 2020, respectively	$	35,000	$	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 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. On July 27, 2021, the company finalized the second amendment to the Exit credit agreement. Under the second amendment, the company obtained confirmation that the Term Loan had been paid in full prior to the amendment date and received one-time waivers related to the disposition of assets.

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 ended (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 ended 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 June 30, 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 the company’s ownership interests in Superior.

At June 30, 2021, we had $35.0 million of long-term borrowings and $2.8 million of letters of credit outstanding under the Exit credit agreement.

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

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 June 30, 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 June 30, 2021, we had no borrowings and $1.4 million of letters of credit outstanding under the Superior credit agreement.

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

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:



	June 30, 2021		December 31, 2020
	(In thousands)
Asset retirement obligation (ARO) liability	$	23,172	$	23,356
Workers’ compensation	11,730		10,164
Finance lease obligations	—		3,216
Contract liability	2,724		4,172
Separation benefit plans	3,237		4,201
Gas balancing liability	4,238		3,997
Other long-term liability	1,321		1,321
	46,422		50,427
Less current portion	7,551		11,168
Total other long-term liabilities	$	38,871	$	39,259

NOTE 10 – 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.

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


	Successor		Predecessor
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(In thousands)
ARO liability, January 1:	$	23,356	$	66,627
Accretion of discount	931		1,169
Liability incurred	1		460
Liability settled	(302)		(435)
Liability sold	(721)		(463)
Revision of estimates (1)	(93)		(3,110)
ARO liability, June 30:	23,172		64,248
Less: current portion	2,132		1,104
Total long-term ARO	$	21,040	$	63,144

_______________________

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 11 – 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 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 stock options or restricted stock units were granted during the three or six months ended June 30, 2020, or during the three months ended March 31, 2021. On April 27, 2021, 109,008 aggregate restricted stock units were granted to the members of the Board pursuant to the LTIP with a weighted-average grant date fair value of $12.90 per unit. The fair value of these grants is measured based on the closing stock price on grant date and compensation expense is being recognized over a thirteen month vesting period in general and administrative on the unaudited condensed consolidated statements of operations.

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:


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(In thousands)
Recognized stock compensation expense	$	216	$	1,567	$	216	$	4,055

Tax benefit on stock-based compensation	$	53	$	392	$	53	$	1,014

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NOTE 12 – 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 9 – Long-Term Debt and Other Long-Term Liabilities. As of June 30, 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 unaudited condensed consolidated balance sheets 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 loss on derivatives in our unaudited condensed consolidated statements of operations.

As of June 30, 2021, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Jul'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$(0.215)

NGPL TEXOK

Jul'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)

Jul'21 - Dec'21

Crude oil - swap

3,373 Bbl/day

$45.57

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 on our unaudited condensed consolidated balance sheets:


		Derivative Liabilities
		Fair Value

	Classification on the unaudited condensed consolidated balance sheets	June 30, 2021		December 31, 2020
		(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	37,960	$	1,047
Long-term	Non-current derivative liability	23,270		4,659
Total derivative liabilities		$	61,230	$	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.

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Following is the effect of derivative instruments on the unaudited condensed consolidated statements of operations for the periods indicated:


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020

	(In thousands)
Loss on derivatives:
Loss on derivatives, included are amounts settled during the period of $(6,403), $(1,243), $(9,707), and $(691), respectively	$	(42,400)	$	(6,937)	$	(65,231)	$	(6,454)
	$	(42,400)	$	(6,937)	$	(65,231)	$	(6,454)

NOTE 13 – FAIR VALUE MEASUREMENTS

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.

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.

•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.

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The following tables set forth our recurring fair value measurements:



	June 30, 2021
	Level 2		Level 3		Effect of Netting		Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	—	$	—	$	—	$	—
Liabilities	(61,230)		—		—		(61,230)
Total commodity derivatives	$	(61,230)	$	—	$	—	$	(61,230)



	December 31, 2020
	Level 2		Level 3		Effect of Netting		Net Amounts Presented
	(In thousands)
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 June 30, 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 and collars 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 commodity derivatives Level 3 fair value measurements:


	Net Derivatives
	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020

	(In thousands)
Beginning of period	$	—	$	948	$	—	$	1,204
Total gains or losses (realized and unrealized):
Included in earnings (1)	—		714		—		1,277
Settlements	—		(819)		—		(1,638)
End of period	$	—	$	843	$	—	$	843
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	$	—	$	(105)	$	—	$	(361)

_______________________

1.Commodity derivative activity is reported in the unaudited condensed consolidated statements of operations in gain (loss) on derivatives.

Our valuation at June 30, 2021 reflected that the risk of non-performance was immaterial.

Warrants. Warrants are recorded at their fair value utilizing the Black-Scholes-Merton option model. The inputs to the model require judgment, including estimating the strike price, expected term, and the associated volatility. The Warrants had fair values of $4.5 million and $0.9 million as of June 30, 2021 and December 31, 2020, respectively, with the change reflected as Loss on change in fair value of warrants in the unaudited condensed consolidated statements of operations. The Warrants will continue to be adjusted to fair value at each reporting period until the Warrants meet the definition of an equity instrument, at which time they will be reported as shareholders' equity and no longer subject to future fair value adjustments.

Fair Value of Other Financial Instruments

At June 30, 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 10 – Asset Retirement Obligations.

NOTE 14 – 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 operating 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 June 30, 2021:


	Amount
	(In thousands)
Ending June 30,
2022	$	3,686
2023	1,528
2024	1,271
2025	86
2026	12
2027 and beyond	57
Total future payments	6,640
Less: Interest	269
Present value of future minimum operating lease payments	6,371
Less: Current portion	3,515
Total long-term operating lease payments	$	2,856

Finance Leases under ASC 842

In 2014, Superior entered into finance lease agreements for 20 compressors with initial terms of seven years and an option to purchase the assets at 10% of their then fair market value at the end of the term. These finance leases were discounted using annual rates of 4.00% and the underlying assets were included in gas gathering and processing equipment. In May 2021, Superior purchased the leased assets for $3.0 million.

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The following table shows information about our lease assets and liabilities on our unaudited condensed consolidated balance sheets:


	Classification on the unaudited condensed consolidated balance sheets	June 30, 2021		December 31, 2020
		(In thousands)
Assets
Operating right of use assets	Right of use assets	$	6,406	$	5,592
Finance right of use assets	Property, plant, and equipment, net	—		7,281
Total right of use assets		$	6,406	$	12,873

Liabilities
Current liabilities:
Operating lease liabilities	Current operating lease liabilities	$	3,515	$	4,075
Finance lease liabilities	Current portion of other long-term liabilities	—		3,216
Non-current liabilities:
Operating lease liabilities	Operating lease liabilities	2,856		1,445
Finance lease liabilities	Other long-term liabilities	—		—
Total lease liabilities		$	6,371	$	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		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(In thousands)
Components of total lease cost:
Amortization of finance leased assets	$	181	$	1,036	$	1,248	$	2,061
Interest on finance lease liabilities	4		60		33		130
Operating lease cost	984		1,395		2,011		2,640
Short-term lease cost (1)	3,179		2,751		5,771		6,742
Variable lease cost	—		83		—		165
Total lease cost	$	4,348	$	5,325	$	9,063	$	11,737

_______________________

1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $0.1 million, $0.4 million, $0.2 million, and $1.4 million for the three and six months ended June 30, 2021 and June 30, 2020, respectively.

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


	Successor		Predecessor
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(In thousands)
Cash paid for amounts in the measurement of lease liabilities:
Operating cash flows for operating leases	$	2,063	$	2,827
Financing cash flows for finance leases	$	3,216	$	2,061

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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

2.4

3.81%

_______________________

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 15 – COMMITMENTS AND CONTINGENCIES

Commitments

We have firm transportation commitments to transport our natural gas from various systems for approximately $1.0 million over the next twelve months and $0.2 million for the six months thereafter.

During the second quarter of 2018, as part of the Superior transaction (see description in Note 16 – 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 Superior. At June 30, 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 June 30, 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 also 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.

NOTE 16 – 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, 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 15 – Commitments and Contingencies or a cumulative return to SP Investor of less than the 7% Liquidation IRR Hurdle provided for SP Investor in the Agreement. Generally, the 7% Liquidation IRR Hurdle calculation requires cumulative distributions to SP Investor in excess of its original $300.0 million investment sufficient to provide SP Investor 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 hypothetical liquidation at book value (HLBV) method of accounting which 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 June 30, 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 unaudited condensed 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.

Superior paid cash distributions totaling $24.7 million in April 2021 related to cumulative available cash as of March 31, 2021 and $7.7 million in July 2021 related to available cash generated during the three months ended June 30, 2021. Unit and SP Investor each received 50% of these distributions. See Note 15 – Commitments and Contingencies for discussion of the Granite Wash/Buffalo Wallow drilling commitment and the potential impact on future distributions.

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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.


	June 30, 2021		December 31, 2020
	(In thousands)

Current assets:
Cash and cash equivalents	$	6,484	$	11,642
Accounts receivable	27,034		27,427
Prepaid expenses and other	3,890		6,746
Total current assets	37,408		45,815
Property and equipment:
Gas gathering and processing equipment	255,338		251,403
Transportation equipment	1,965		1,748
	257,303		253,151
Less accumulated depreciation, depletion, amortization, and impairment	26,736		10,466
Net property and equipment	230,567		242,685
Right of use asset	4,419		2,823
Other assets	1,973		2,309
Total assets	$	274,367	$	293,632

Current liabilities:
Accounts payable	$	20,349	$	17,045
Accrued liabilities	4,541		3,777
Current operating lease liability	1,646		1,762
Current portion of other long-term liabilities	2,116		5,799
Total current liabilities	28,652		28,383

Operating lease liability	626		1,013
Other long-term liabilities	2,773		1,589
Total liabilities	$	32,051	$	30,985

NOTE 17 – INCOME TAXES

For the three and six months ended June 30, 2021, the company’s effective income tax rate was 0% compared to 2.9% and 0.96% for the three and six months ended June 30, 2020. The decrease was due to the continued need of a full valuation allowance against our net deferred tax asset coming out of bankruptcy and as a result of fresh start accounting. These rates differ from the statutory rate of 21% mostly due to changes in our valuation allowance, our non-controlling interests in consolidated subsidiaries, and state income taxes.

Deferred Tax Asset Valuation Allowance

The company has concluded that it is more likely than not that the net deferred tax asset will not be realized and has recorded a full valuation allowance, reducing the net deferred tax asset as of June 30, 2021, to zero. The company will continue to evaluate whether the valuation allowance is needed in future reporting periods and it will remain until the company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, significant improvements in commodity prices, significant increase in rig utilization, a material and sizable asset acquisition, and taxable events that could result from one or more future potential transactions. The valuation allowance does not prohibit the company from utilizing the tax attributes if the company recognizes taxable income. As long as the company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the company will not have significant deferred income tax expense or benefit.

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NOTE 18 – 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.

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


	Successor
	Three Months Ended June 30, 2021
	Oil and Natural Gas (2)		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations (3)		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	59,776	$	—	$	—	$	—	$	(17,806)	$	41,970
Contract drilling	—		18,061		—		—		—		18,061
Gas gathering and processing	—		—		66,323		—		7,703		74,026
Total revenues	59,776		18,061		66,323		—		(10,103)		134,057
Expenses:
Operating costs:
Oil and natural gas	16,350		—		—		—		(863)		15,487
Contract drilling	—		14,080		—		—		—		14,080
Gas gathering and processing	—		—		55,176		—		(10,120)		45,056
Total operating costs	16,350		14,080		55,176		—		(10,983)		74,623
Depreciation, depletion, and amortization	6,476		1,570		8,064		254		—		16,364

Total expenses	22,826		15,650		63,240		254		(10,983)		90,987

General and administrative	—		—		—		4,871		880		5,751
Gain on disposition of assets	(67)		(1,618)		—		(25)		—		(1,710)
Income (loss) from operations	37,017		4,029		3,083		(5,100)		—		39,029
Loss on derivatives	—		—		—		(42,400)		—		(42,400)
Loss on change in fair value of warrants	—		—		—		(3,574)		—		(3,574)

Reorganization items, net	—		—		—		(1,852)		—		(1,852)
Interest, net	—		—		641		(1,128)		—		(487)
Other	34		11		(850)		(26)		—		(831)
Income (loss) before income taxes	$	37,051	$	4,040	$	2,874	$	(54,080)	$	—	$	(10,115)

_______________________

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.

2.Reflects one-time adjustments to correct errors discovered in our prior period accrual of oil and natural gas revenues as well as oil and natural gas operating costs, as described in Note 2 - Summary Of Significant Accounting Policies.

3.Reflects one-time adjustments to correct errors discovered in our inter-segment eliminations presentation, as described in Note 2 - Summary Of Significant Accounting Policies.

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	Predecessor
	Three Months Ended June 30, 2020
	Oil and Natural Gas		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	26,957	$	—	$	—	$	—	$	(1)	$	26,956
Contract drilling	—		29,202		—		—		—		29,202
Gas gathering and processing	—		—		37,719		—		(4,870)		32,849
Total revenues	26,957		29,202		37,719		—		(4,871)		89,007
Expenses:
Operating costs:
Oil and natural gas	72,354		—		—		—		(814)		71,540
Contract drilling	—		20,951		—		—		—		20,951
Gas gathering and processing	—		—		26,669		—		(4,057)		22,612
Total operating costs	72,354		20,951		26,669		—		(4,871)		115,103
Depreciation, depletion, and amortization	22,059		2,946		10,348		607		—		35,960
Impairments	109,318		—		—		—		—		109,318
Total expenses	203,731		23,897		37,017		607		(4,871)		260,381
General and administrative	—		—		—		25,814		—		25,814
(Gain) loss on disposition of assets	(45)		(548)		(9)		1,479		—		877
Income (loss) from operations	(176,729)		5,853		711		(27,900)		—		(198,065)
Loss on derivatives	—		—		—		(6,937)		—		(6,937)
Write-off of debt issuance costs	—		—		—		(2,426)		—		(2,426)
Reorganization items, net	—		—		—		(7,027)		—		(7,027)
Interest, net	—		—		(542)		(7,066)		—		(7,608)
Other	9		6		22		6		—		43
Income (loss) before income taxes	$	(176,720)	$	5,859	$	191	$	(51,350)	—		$	(222,020)

_______________________

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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	Successor
	Six Months Ended June 30, 2021
	Oil and Natural Gas (2)		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	114,801	$	—	$	—	$	—	$	(17,807)	$	96,994
Contract drilling	—		33,735		—		—		—		33,735
Gas gathering and processing	—		—		125,932		—		(1,707)		124,225
Total revenues	114,801		33,735		125,932		—		(19,514)		254,954
Expenses:
Operating costs:
Oil and natural gas	36,343		—		—		—		(1,707)		34,636
Contract drilling	—		25,951		—		—		—		25,951
Gas gathering and processing	—		—		104,286		—		(19,567)		84,719
Total operating costs	36,343		25,951		104,286		—		(21,274)		145,306
Depreciation, depletion, and amortization	14,131		3,145		16,096		503		—		33,875

Total expenses	50,474		29,096		120,382		503		(21,274)		179,181

General and administrative	—		—		—		11,160		1,760		12,920
(Gain) loss on disposition of assets	(87)		(2,146)		75		(24)		—		(2,182)
Income (loss) from operations	64,414		6,785		5,475		(11,639)		—		65,035
Loss on derivatives	—		—		—		(65,231)		—		(65,231)
Loss on change in fair value of warrants	—		—		—		(3,574)		—		(3,574)

Reorganization items, net	—		—		—		(2,988)		—		(2,988)
Interest, net	—		—		(416)		(2,777)		—		(3,193)
Other	90		16		(839)		(22)		—		(755)
Income (loss) before income taxes	$	64,504	$	6,801	$	4,220	$	(86,231)	$	—	$	(10,706)

_______________________ ____________________

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.

2.Reflects a one-time adjustment to correct an error discovered in our prior period accrual of oil and natural gas operating costs, as described in Note 2 - Summary Of Significant Accounting Policies.

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	Predecessor
	Six Months Ended June 30, 2020
	Oil and Natural Gas			Contract Drilling			Mid-Stream			Corporate and Other			Eliminations			Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	75,481		$	—		$	—		$	—		$	(3)		$	75,478
Contract drilling	—			65,834			—			—			—			65,834
Gas gathering and processing	—			—			80,399			—			(10,328)			70,071
Total revenues	75,481			65,834			80,399			—			(10,331)			211,383
Expenses:
Operating costs:
Oil and natural gas	103,769			—			—			—			(1,566)			102,203
Contract drilling	—			46,400			—			—			—			46,400
Gas gathering and processing	—			—			58,988			—			(8,765)			50,223
Total operating costs	103,769			46,400			58,988			—			(10,331)			198,826
Depreciation, depletion, and amortization	58,787			14,691			22,621			1,478			—			97,577
Impairments	377,154			410,126			63,962			—			—			851,242
Total expenses	539,710			471,217			145,571			1,478			(10,331)			1,147,645
Loss on abandonment of assets	17,554		#N/A	—		#N/A	—		#N/A	—		#N/A	—		#N/A	17,554
General and administrative	—			—			—			37,367			—			37,367
(Gain) loss on disposition of assets	(58)			(139)			(15)			1,479			—			1,267
Loss from operations	(481,725)			(405,244)			(65,157)			(40,324)			—			(992,450)
Loss on derivatives	—			—			—			(6,454)			—			(6,454)
Write-off of debt issuance costs	—			—			—			(2,426)			—			(2,426)
Reorganization items, net	—			—			—			(7,027)			—			(7,027)
Interest, net	—			—			(1,060)			(19,805)			—			(20,865)
Other	30			23			39			11			—			103
Loss before income taxes	$	(481,695)		$	(405,221)		$	(66,178)		(76,025)			$	—		$	(1,029,119)

_______________________

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 19 – 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 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 were called "Parent",

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

•Superior and its subsidiaries and the Operator were 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 June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	56,159	$	37,719	$	(4,871)	$	89,007
Expenses:
Operating costs	—		93,305		26,671		(4,873)		115,103
Depreciation, depletion, and amortization	607		25,005		10,348		—		35,960
Impairments	—		109,318		—		—		109,318
General and administrative	—		25,814		—		—		25,814
(Gain) loss on disposition of assets	1,479		(593)		(9)		—		877
Total operating costs	2,086		252,849		37,010		(4,873)		287,072
Income (loss) from operations	(2,086)		(196,690)		709		2		(198,065)
Interest, net	(7,066)		—		(542)		—		(7,608)
Write-off of debt issuance costs	(2,426)		—		—		—		(2,426)
Loss on derivatives	(6,937)		—		—		—		(6,937)
Reorganization items, net	(2,205)		(4,822)		—		—		(7,027)
Other, net	4		18		21		—		43
Income (loss) before income taxes	(20,716)		(201,494)		188		2		(222,020)
Income tax benefit	(6,455)		—		—		—		(6,455)
Equity in net earnings from investment in subsidiaries, net of taxes	(201,304)		—		—		201,304		—
Net income (loss)	(215,565)		(201,494)		188		201,306		(215,565)
Less: net income attributable to non-controlling interest	84		—		84		(84)		84
Net income (loss) attributable to Unit Corporation	$	(215,649)	$	(201,494)	$	104	$	201,390	$	(215,649)

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	Predecessor
	Six Months Ended June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	141,315	$	80,399	$	(10,331)	$	211,383
Expenses:
Operating costs	—		150,169		58,988		(10,331)		198,826
Depreciation, depletion, and amortization	1,478		73,478		22,621		—		97,577
Impairments	—		787,280		63,962		—		851,242
Loss on abandonment of assets	—		17,554		—		—		17,554
General and administrative	—		37,367		—		—		37,367
(Gain) loss on disposition of assets	1,479		(197)		(15)		—		1,267
Total operating costs	2,957		1,065,651		145,556		(10,331)		1,203,833
Loss from operations	(2,957)		(924,336)		(65,157)		—		(992,450)
Interest, net	(19,805)		—		(1,060)		—		(20,865)
Write-off of debt issuance costs	(2,426)		—		—		—		(2,426)
Loss on derivatives	(6,454)		—		—		—		(6,454)
Reorganization items, net	(2,205)		(4,822)		—		—		(7,027)
Other, net	11		53		39		—		103
Loss before income taxes	(33,836)		(929,105)		(66,178)		—		(1,029,119)
Income tax benefit	(9,880)		—		—		—		(9,880)
Equity in net earnings from investment in subsidiaries, net of taxes	(995,283)		—		—		995,283		—
Net loss	(1,019,239)		(929,105)		(66,178)		995,283		(1,019,239)
Less: net loss attributable to non-controlling interest	(33,096)		—		(33,096)		33,096		(33,096)
Net loss attributable to Unit Corporation	$	(986,143)	$	(929,105)	$	(33,082)	$	962,187	$	(986,143)

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Condensed Consolidating Statements of Cash Flows (Unaudited)


	Predecessor
	Six Months Ended June 30, 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	$	(201,699)	$	59,486	$	20,117	$	148,563	$	26,467
INVESTING ACTIVITIES:
Capital expenditures	(760)		(13,428)		(9,616)		—		(23,804)
Producing properties and other acquisitions	—		(210)		—		—		(210)
Proceeds from disposition of assets	1,169		3,253		75		—		4,497
Net cash provided by (used in) investing activities	409		(10,385)		(9,541)		—		(19,517)
FINANCING ACTIVITIES:
Borrowings under credit agreement, including borrowings under DIP credit facility	47,300		—		32,100		—		79,400
Payments under credit agreement	(23,500)		—		(14,600)		—		(38,100)
DIP financing costs	(990)		—		—		—		(990)
Intercompany borrowings (advances), net	198,503		(49,169)		(771)		(148,563)		—
Payments on finance leases	—		—		(2,061)		—		(2,061)
Employee taxes paid by withholding shares	(43)		—		—		—		(43)

Bank overdrafts	(7,269)		—		(1,464)		—		(8,733)
Net cash provided by (used in) financing activities	214,001		(49,169)		13,204		(148,563)		29,473
Net increase (decrease) in cash and cash equivalents	12,711		(68)		23,780		—		36,423
Cash and cash equivalents, beginning of period	503		68		—		—		571
Cash and cash equivalents, end of period	$	13,214	$	—	$	23,780	$	—	$	36,994

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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.

Our corporate headquarters building and land are owned by our wholly owned subsidiary 8200 Unit Drive, L.L.C. (8200 Unit). See Note 5 - Divestitures for discussion on the headquarters building and land.

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 selective drilling activities in core areas. 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 June 30, 2021 and references to "Predecessor Period" refer to the results of operations for the period January 1, 2020 through June 30, 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, including any new variants, on our business. This includes how it has and may continue to impact our operations, financial results, liquidity, customers, employees, and vendors as new COVID-19 variants may have undetermined impacts to our business. In response to the pandemic, we have implemented various measures to ensure we are conducting our business in a safe and secure manner.

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

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

_________________________

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

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Stock Repurchase Program

In June 2021, the Board authorized repurchasing up to $25.0 million of the company’s outstanding common stock. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. The company has no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice. As of June 30, 2021, no repurchases have been made under the share repurchase program.

Issuance of New Common Stock

On July 26, 2021, as contemplated by the Plan, the company distributed approximately 680,000 additional shares of New Common Stock to holders of the subordinated notes claims, as a result of the pro rata distribution of shares of New Common Stock out of the equity reserves established under the Plan for certain disputed claims against the company and UPC. The shares of New Common Stock were distributed pursuant to Section 1145 of the Bankruptcy Code (which generally exempts from registration under the federal and state securities laws the issuance of securities in exchange for interests in or claims against a debtor under a plan of reorganization). Pursuant to the Plan, all shares of New Common Stock were distributed in book-entry form through the facilities of The Depository Trust Company (DTC).

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. The exercise price of the Warrants will be determined and the Warrants will become exercisable once all general unsecured claims are resolved.

On December 21, 2020, February 11, 2021 and July 29, 2021, the company issued approximately 1.8 million, 42,500 and 10,500 Warrants, respectively, to holders of the company’s Old Common Stock that did not opt-out of the releases under the Plan and that owned their shares of old common stock through Direct Registration. Under the Plan, all Warrants were issued in book-entry form through the facilities of DTC.

The company expects to issue approximately 26,100 more Warrants to the holders of the Old Common Stock that did not opt-out of the releases under the Plan and owned their shares through Direct Registration.

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.

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


	Successor		Predecessor		Percent Change (1)
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(In thousands except percentages)
Net cash provided by operating activities	73,965		26,467		179	%
Net cash provided by (used in) investing activities	7,605		(19,517)		139	%
Net cash provided by (used in) financing activities	(87,295)		29,473		NM
Net increase (decrease) in cash, restricted cash and cash equivalents	$	(5,725)	$	36,423

_________________________

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

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 six months of 2021 increased by $47.5 million as compared to the first six 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.

Cash Flows from Investing Activities

We have historically dedicated a substantial portion of our capital budgets to our exploration for and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells. Although we have curtailed our spending throughout 2020 and into 2021, we expect the majority of future capital budgets to be focused on development or acquisitions of producing oil and gas properties.

Net cash provided by (used in) investing activities increased by $27.1 million for the first six months of 2021 compared to the first six months of 2020. The change was due primarily to a decrease in capital expenditures resulting from a decrease in the number of wells drilled and oil and gas property acquisitions as well as an increase in proceeds received from the disposition of non-core assets.

Cash Flows from Financing Activities

Net cash provided by (used in) financing activities decreased by $116.8 million for the first six months of 2021 compared to the first six months of 2020. The decrease was primarily due to lower net borrowings under our credit agreements, higher payments on our credit agreements, and lower bank overdrafts, partially offset by distributions to non-controlling interests and the repurchase of common stock.

At June 30, 2021, we had unrestricted cash and cash equivalents totaling $7.0 million and had borrowed $35.0 million of the amounts available under the Exit credit agreement. We did not have any outstanding borrowings under our Superior credit agreement.

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Below, we summarize certain financial information as of June 30:


	Successor		Predecessor
	2021		2020
	(In thousands)
Working capital	$	(38,200)	$	(104,738)
Current portion of long-term debt	$	—	$	124,000
Debtor-in-possession financing	$	—	$	8,000
Long-term debt	$	35,000	$	34,000
Shareholders’ equity attributable to Unit Corporation	$	155,562	$	(128,176)

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 negative working capital of $38.2 million and $104.7 million as of June 30, 2021 and 2020, respectively. The increase in working capital is primarily due to the settlement of the liabilities subject to compromise and an increase in accounts receivable, partially offset by higher current derivative liabilities, lower unrestricted cash and cash equivalents, and higher accounts payable. At June 30, 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 $38.0 million as of June 30, 2021 and decreased working capital by $5.0 million as of June 30, 2020.

Our Credit Agreements

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 June 30, 2021, we had $35.0 million outstanding long-term borrowings under the Exit credit agreement. During the six month period ended June 30, 2021, the company repaid $67.9 million of borrowings under the Exit credit agreement 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. On July 27, 2021, the company finalized the second amendment to the Exit credit agreement. Under the second amendment, the company obtained confirmation that the Term Loan had been paid in full prior to the amendment date and received one-time waivers related to the disposition of assets.

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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 10 gross wells (0.77 net wells) drilled by other operators in the first six months of 2021 compared to 27 gross wells (6.16 net wells) drilled by other operators in which we participated in the first six months of 2020.

Capital expenditures for oil and gas properties on the full cost method for the first six months of 2021 by this segment, excluding a $1.1 million reduction in the ARO liability, totaled $5.9 million. Capital expenditures for the first six months of 2020, excluding $0.2 million for acquisitions and a $3.4 million reduction in the ARO liability, totaled $9.9 million.

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

We sold $4.4 million of additional non-core oil and natural gas assets, net of related expenses, during the first six months of 2021, compared to $0.9 million during the first six 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 incurred $0.5 million in capital expenditures during the first six months of 2021, compared to $2.8 million for capital expenditures during the first six months of 2020.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. During the first six months of 2021, our mid-stream segment incurred $4.1 million in capital expenditures as compared to $9.0 million in the first six months of 2020. For 2021, we estimate total capital expenditures of approximately $15.0 million, 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 June 30, 2021, based on our second quarter 2021 average daily production, the approximated percentages of our production under derivative contracts are as follows:


	2021		2022		2023
Daily oil production	76	%	54	%	31	%
Daily natural gas production	59	%	48	%	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 June 30, 2021 evaluation, we believe the risk of non-performance by our counterparties is not material. At June 30, 2021, the fair values of the net liabilities we had with each of the counterparties to our commodity derivative transactions are as follows:


	June 30, 2021
	(In thousands)
Bank of Oklahoma	$	(60,369)
Bank of Montreal	(861)
Total net liabilities	$	(61,230)

Below is the effect of derivative instruments on the unaudited condensed consolidated statements of operations for the periods indicated:


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(In thousands)
Loss on derivatives:
Loss on derivatives, included are amounts settled during the period of ($6,403), ($1,243), ($9,707), and ($691), respectively	$	(42,400)	$	(6,937)	$	(65,231)	$	(6,454)
	$	(42,400)	$	(6,937)	$	(65,231)	$	(6,454)

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Results of Operations

Quarter Ended June 30, 2021 versus Quarter Ended June 30, 2020

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


	Successor			Predecessor			Percent Change (1)
	Quarter Ended June 30, 2021			Quarter Ended June 30, 2020
	(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations	$	144,160		$	93,878		54	%
Total revenue, after inter-segment eliminations	$	134,057		$	89,007		51	%
Net loss	$	(10,115)		$	(215,565)		95	%
Net income attributable to non-controlling interest	$	2,879		$	84		NM
Net loss attributable to Unit Corporation	$	(12,994)		$	(215,649)		94	%

Oil and Natural Gas:
Revenue, before inter-segment eliminations	$	59,776		$	26,957		122	%
Operating costs, before inter-segment eliminations	$	16,350		$	72,354		(77)	%
Average oil price (Bbl)	$	48.38		$	18.14		167	%
Average oil price per barrel received excluding derivatives	$	64.38		$	20.98		NM
Average NGLs price (Bbl)	$	17.95		$	4.11		NM
Average NGLs price per barrel received excluding derivatives	$	17.95		$	4.11		NM
Average natural gas price (Mcf)	$	2.98		$	1.08		176	%
Average natural gas price per Mcf received excluding derivatives	$	3.00		$	1.05		186	%
Oil production (MBbls)	389			546			(29)	%
NGL production (MBbls)	662			862			(23)	%
Natural gas production (MMcf)	7,543			9,576			(21)	%


Contract Drilling:
Revenue, before inter-segment eliminations	$	18,061		$	29,202		(38)	%
Operating costs, before inter-segment eliminations	$	14,080		20,951			(33)	%



Average number of drilling rigs in use	10.0			9.1			10	%
Total drilling rigs available for use at the end of the period	21.0			58.0			(64)	%
Average dayrate on daywork contracts	$	18,269		$	18,340		—	%

Mid-Stream:
Revenue, before inter-segment eliminations	$	66,323		$	37,719		76	%
Operating costs, before inter-segment eliminations	$	55,176		$	26,669		107	%


Gas gathered--Mcf/day	293,220			404,831			(28)	%
Gas processed--Mcf/day	127,399			155,555			(18)	%
Gas liquids sold--gallons/day	441,369			637,420			(31)	%
Number of natural gas gathering systems	17			18			(6)	%
Number of processing plants	11			11			—	%

Corporate and Other:

General and administrative expense, before inter-segment eliminations	$	4,871		$	25,814		(81)	%


Other income (expense):

Interest expense, net	$	(487)		$	(7,666)		(94)	%
Write-off of debt issuance costs	$	—		$	(2,426)		(100)	%
Reorganization items, net	$	(1,852)		$	(7,027)		(74)	%
Loss on derivatives	$	(42,400)		$	(6,937)		NM
Loss on change in fair value of warrants	$	(3,574)		$	—		—	%

Income tax benefit	$	—		$	(6,455)		100	%
Average interest rate	6.5		%	6.1		%	7	%
Average long-term debt outstanding	$	62,646		$	410,593		(85)	%

_________________________

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 $32.8 million or 122% in the second quarter of 2021 as compared to the second quarter of 2020 primarily due to higher commodity prices, partially offset by lower production volumes. In the second quarter of 2021, as compared to the second quarter of 2020, oil production decreased 29%, natural gas production decreased 21%, and NGLs production decreased 23%. Including derivatives settled, average oil prices increased 167% to $48.38 per barrel, average natural gas prices increased 176% to $2.98 per Mcf, and NGLs prices increased over 200% to $17.95 per barrel.

Oil and natural gas operating costs decreased $56.0 million or 77% between the comparative second quarters of 2021 and 2020 primarily due to the settlement of Predecessor Period liabilities subject to compromise under the Plan.

Contract Drilling

Drilling revenues decreased $11.1 million or 38% in the second quarter of 2021 versus the second quarter of 2020. The decrease was driven primarily by the absence of early termination fees. During the second quarter of 2021, we recorded no early termination fees compared to $9.2 million of early termination fees recorded in second quarter of 2020.

Drilling operating costs decreased $6.9 million or 33% between the comparative second quarters of 2021 and 2020. The change was primarily due to a decrease in incurred separation benefit expenses recognized in the Predecessor Period.

Mid-Stream

Our mid-stream revenues increased $28.6 million or 76% in the second quarter of 2021 as compared to the second quarter of 2020 primarily due to higher gas, NGLs, and condensate prices, partially offset by lower volumes. Gas processed volumes per day decreased 18% between the comparative quarters primarily due to connecting fewer new wells and declining volumes on most of our major processing systems. Gas gathered volumes per day decreased 28% between the comparative quarters due to declining volumes and fewer new well connections.

Operating costs increased $28.5 million or 107% in the second quarter of 2021 compared to the second quarter of 2020 primarily due to higher gas, NGLs, and condensate prices, partially offset by lower purchase volumes.

General and Administrative

Corporate general and administrative expenses decreased $20.9 million or 81% in the second quarter of 2021 as compared to the second quarter of 2020 primarily due to reduced consulting and outside legal fees. We incurred $16.5 million in advisory and restructuring fees in the second quarter of 2020.

Other Income (Expense)

Interest expense decreased $7.2 million between the comparative second quarters of 2021 and 2020 primarily due to an 85% decrease in average long-term debt outstanding, partially offset by a higher average interest rate. Our average interest rate increased from 6.1% in the second quarter of 2020 to 6.5% in the second quarter of 2021 and our average debt outstanding decreased $347.9 million in the second quarter of 2021 compared to the second quarter of 2020 primarily due to the settlement of the Notes under the Plan and payments made under the Exit credit agreement.

Write-off of Debt Issuance Costs

Due to the termination of the remaining commitments of the Predecessor Period Unit credit agreement, unamortized debt issuance costs of $2.4 million were written off during the second quarter of 2020.

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.

Loss on Derivatives

Loss on derivatives increased by $35.5 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

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Loss on Change in Fair Value of Warrants

Loss on change in fair value of warrants increased by $3.6 million primarily due to changes in the underlying assumptions used to estimate the fair value, including estimated strike price, entity value, duration to exercise and other inputs.

Income Tax Benefit

We did not record an income tax benefit in the second quarter of 2021 compared to $6.5 million in the second quarter of 2020 due to the company's full valuation allowance against our net deferred tax asset. Our effective tax rate was 0% for the second quarter of 2021 compared to 2.91% for the second quarter 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 second quarter of 2021.

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Results of Operations

Six Months Ended June 30, 2021 versus Six Months Ended June 30, 2020

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


	Successor			Predecessor			Percent Change (1)
	Six Months Ended June 30, 2021			Six Months Ended June 30, 2020
	(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations	$	274,468		$	221,714		24	%
Total revenue, after inter-segment eliminations	$	254,954		$	211,383		21	%
Net loss	$	(10,706)		$	(1,019,239)		99	%
Net income (loss) attributable to non-controlling interest	$	4,225		$	(33,096)		113	%
Net loss attributable to Unit Corporation	$	(14,931)		$	(986,143)		99	%

Oil and Natural Gas:
Revenue, before inter-segment eliminations	$	114,801		$	75,481		52	%
Operating costs, before inter-segment eliminations	$	36,343		$	103,769		(65)	%


Average oil price (Bbl)	$	47.82		$	32.93		45	%
Average oil price per barrel received excluding derivatives	$	60.12		$	34.20		76	%
Average NGLs price (Bbl)	$	17.95		$	3.67		NM
Average NGLs price per barrel received excluding derivatives	$	17.95		$	3.67		NM
Average natural gas price (Mcf)	$	2.87		$	1.16		147	%
Average natural gas price per Mcf received excluding derivatives	$	2.86		$	1.12		155	%
Oil production (MBbls)	801			1,220			(34)	%
NGLs production (MBbls)	1,303			1,827			(29)	%
Natural gas production (MMcf)	14,946			20,378			(27)	%


Contract Drilling:
Revenue, before inter-segment eliminations	$	33,735		$	65,834		(49)	%
Operating costs, before inter-segment eliminations	$	25,951		$	46,400		(44)	%




Average number of drilling rigs in use	9.7			13.9			(30)	%
Total drilling rigs available for use at the end of the period	21			58			(64)	%
Average dayrate on daywork contracts	$	18,200		$	19,165		(5)	%

Mid-Stream:
Revenue, before inter-segment eliminations	$	125,932		$	80,399		57	%
Operating costs, before inter-segment eliminations	$	104,286		$	58,988		77	%


Gas gathered--Mcf/day	296,396			397,037			(25)	%
Gas processed--Mcf/day	124,285			160,943			(23)	%
Gas liquids sold--gallons/day	425,277			582,546			(27)	%
Number of natural gas gathering systems	17			18			(6)	%
Number of processing plants	11			11			—	%

Corporate and Other:

General and administrative expense, before inter-segment eliminations	$	11,160		$	37,367		(70)	%


Other income (expense):

Interest expense, net	$	(2,777)		$	(20,923)		(87)	%
Write-off of debt issuance costs	$	—		$	(2,426)		(100)	%
Reorganization items, net	$	(2,988)		$	(7,027)		58	%
Loss on derivatives	$	(65,231)		$	(6,454)		NM

Loss on change in fair value of warrants	$	(3,574)		$	—		—	%
Income tax benefit	$	—		$	(9,880)		100	%
Average interest rate	6.7		%	6.2		%	7	%
Average long-term debt outstanding	$	77,852		$	586,048		(87)	%

_________________________

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 $39.3 million or 52% in the first six months of 2021 as compared to the first six months of 2020 primarily due to higher commodity prices partially offset by lower production volumes. The decline in volumes was due to normal well production declines which have not been offset by new drilling or acquisitions.

Oil and natural gas operating costs decreased $67.4 million or 65% between the comparative first six months of 2021 and 2020 primarily due to the settlement of Predecessor Period liabilities subject to compromise under the Plan.

Contract Drilling

Drilling revenues decreased $32.1 million or 49% in the first six months of 2021 versus the first six months of 2020. The decrease was due primarily to a 30% decrease in the average number of drilling rigs in use and a 5% decrease in the average dayrate. Average drilling rig utilization decreased from 13.9 drilling rigs in the first six months of 2020 to 9.7 drilling rigs in the first six months of 2021.

Drilling operating costs decreased $20.4 million or 44% between the comparative first six months of 2021 and 2020. The decrease was due primarily to the reduced number of drilling rigs operating.

During the first six months of 2021, 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, 11 are currently working, 6 are actively being marketed, and the remaining 4 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 $45.5 million or 57% in the first six months of 2021 as compared to the first six months of 2020 primarily due to higher prices, partially offset by lower volumes. Gas processed volumes per day decreased 23% between the comparative periods primarily due to declining volumes and fewer new wells connected to our processing systems. Gas gathered volumes per day decreased 25% between the comparative periods also due to declining volumes and fewer new wells connected to our gathering systems. We also experienced overall lower volumes due to the February 2021 winter storm.

Operating costs increased $45.3 million or 77% in the first six months of 2021 compared to the first six months of 2020 primarily due to higher gas, NGLs, and condensate prices, partially offset by lower purchase volumes.

General and Administrative

Corporate general and administrative expenses decreased $26.2 million or 70% in the first six months of 2021 as compared to the first six months of 2020 primarily due to reduction in consulting and legal fees paid prior to filing for bankruptcy.

Other Income (Expense)

Interest expense decreased $18.1 million between the comparative first six months of 2021 and 2020 primarily due to a reduction in average long-term debt outstanding, partially offset by a higher average interest rate. Our average interest rate increased from 6.2% in the first six months of 2020 to 6.7% in the first six months of 2021 and our average debt outstanding decreased $508.2 million in the first six months of 2021 compared to the first six months of 2020 primarily due to the Notes being settled with the Plan and payments made under the Exit credit agreement.

Write-off of Debt Issuance Costs

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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.

Loss on Derivatives

Loss on derivatives increased by $58.8 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Loss on Change in Fair Value of Warrants

Income Tax Benefit

We did not record an income tax benefit in the first six months of 2021 compared to $9.9 million in the first six months of 2020 due to the company's full valuation allowance against our net deferred tax asset. Our effective tax rate was 0% for the first six months of 2021 compared to 0.96% for the first six 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 six months of 2021.

Item 3. Quantitative and Qualitative Disclosures 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 six 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 $130,000 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 $220,000 per month ($2.6 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.

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At June 30, 2021, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Jul'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$(0.215)

NGPL TEXOK

Jul'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)

Jul'21 - Dec'21

Crude oil - swap

3,373 Bbl/day

$45.57

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 June 30, 2021 would reduce our annual pre-tax cash flow by approximately $0.4 million. For further information, see Note 9 – Long-Term Debt and Other Long-Term Liabilities.

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 June 30, 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.

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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 June 30, 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 and re-assigned certain existing personnel into key positions. And we are conducting process improvement sessions with third party experts to enhance and augment business processes and utilization of system capabilities for greater effectiveness, efficiency, and scalability.

Our management believes the measures described above will remediate this material weakness and improve the overall effectiveness of internal control over financial reporting. 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 controls operate for a sufficient period of time and management has tested the effectiveness of those controls. Management expects these remedial actions and any other remedial actions related to the material weakness to be effectively implemented in 2021.

Changes in Internal Controls. There were no other changes in our ICFR during the quarter ended June 30, 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 15 – 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

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:


3.1			Amended and Restated Certificate of Incorporation.

10.1			Second Amendment to Amended and Restated Credit Agreement effective July 26, 2021.

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.

104			Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101)

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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:	August 16, 2021	By: /s/ Philip B. Smith
		PHILIP B. SMITH
		President and Chief Executive Officer

Date:	August 16, 2021	By: /s/ Thomas D. Sell
		THOMAS D. SELL
		Chief Financial Officer