UNTC 10-Q Quarterly Report Sept. 30, 2021

UNIT CORP

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PROXIES

DEF 14A	Filed on March 26, 2019
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DEF 14A	Filed on March 16, 2012
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DEF 14A	Filed on March 19, 2010

unt-20210930

Table of Contents

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 September 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 November 12, 2021, 10,260,037 shares of the registrant'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	41

Item 3.	Quantitative and Qualitative Disclosure s About Market Risk	53

Item 4.	Controls and Procedures	54

	PART II. Other Information

Item 1.	Legal Proceedings	56

Item 1A.	Risk Factors	56

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56

Item 3.	Defaults Upo n Senior Securities	57

Item 4.	Mine Safety Disclosures	57

Item 5.	Other Information	57

Item 6.	Exhibits	58

Signatures		59

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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;

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

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

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

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

• expansion and growth of our business and operations;

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

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

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

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

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

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

• any projected production guidelines we may issue;

• our anticipated capital budgets;

• our financial condition and liquidity;

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

• the effects of world health events, including the COVID-19 pandemic;

• 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;

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• 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;

• risks associated with future weather conditions;

• decreases or increases in commodity prices;

• the consequences of any divestitures of assets;

• 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;

• our ability to retain and recruit talent if vaccination mandates or other similar regulation is required; 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.”

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	September 30, 2021		December 31, 2020
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	49,566	$	12,145
Restricted cash	—		569
Accounts receivable, net of allowance for credit losses of $ 2,573 and $ 3,783 at September 30, 2021 and December 31, 2020, respectively	72,405		57,846



Current income tax receivable	22		1,150

Prepaid expenses and other	6,120		11,212
Total current assets	128,113		82,922
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties	225,786		238,581
Unproved properties not being amortized	247		1,591
Drilling equipment	64,278		63,687
Gas gathering and processing equipment	259,642		251,404
Land and building	—		32,635
Transportation equipment	3,750		3,130
Other	8,892		9,961
	562,595		600,989
Less accumulated depreciation, depletion, amortization, and impairment	103,794		54,189
Net property and equipment	458,801		546,800


Right of use asset (Note 14)	13,800		5,592
Other assets	16,086		14,389
Total assets (1)	$	616,800	$	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


	September 30, 2021		December 31, 2020
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	47,106	$	37,368
Accrued liabilities (Note 8)	26,979		25,204
Current operating lease liability (Note 14)	4,399		4,075
Current portion of long-term debt (Note 9)	—		600
Current derivative liabilities (Note 12)	59,962		1,047
Warrant liability (Note 13)	13,512		885
Current portion of other long-term liabilities (Note 9)	6,522		11,168
Total current liabilities	158,480		80,347
Long-term debt (Note 9)	3,100		98,400
Non-current derivative liabilities (Note 12)	28,069		4,659
Operating lease liability (Note 14)	9,387		1,445
Other long-term liabilities (Note 9)	41,474		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 10,971,963 outstanding at September 30, 2021 and 12,000,000 shares issued and outstanding at December 31, 2020	120		120
Treasury stock (Note 6)	( 19,882 )		—
Capital in excess of par value	197,479		197,242

Retained deficit	( 28,213 )		( 18,140 )
Total shareholders’ equity attributable to Unit Corporation	149,504		179,222
Non-controlling interests in consolidated subsidiaries	226,786		246,371
Total shareholders' equity	376,290		425,593
Total liabilities (1) and shareholders’ equity	$	616,800	$	649,703

_______________________

(1) Unit Corporation's consolidated total assets as of September 30, 2021 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $ 51.3 million and $ 232.7 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated cash and cash equivalents of $ 49.6 million includes $ 12.3 million held by its VIE. Unit Corporation's consolidated total liabilities as of September 30, 2021 include total current and long-term liabilities of the VIE of $ 36.9 million and $ 5.6 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)


	2021		2020				2021		2020
	Three Months Ended September 30, 2021		One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
	Successor		Successor		Predecessor		Successor		Successor		Predecessor
Revenues:					(In thousands except per share amounts)
Oil and natural gas	$	52,880	$	13,643	$	27,961	$	149,874	$	13,643	$	103,439
Contract drilling	19,158		4,414		7,685		52,893		4,414		73,519
Gas gathering and processing	91,210		14,789		29,928		215,435		14,789		99,999
Total revenues	163,248		32,846		65,574		418,202		32,846		276,957
Expenses:
Operating costs:
Oil and natural gas	21,210		6,674		15,488		55,846		6,674		117,691
Contract drilling	15,357		2,989		5,410		41,308		2,989		51,810
Gas gathering and processing	62,621		9,852		17,822		147,340		9,852		68,045
Total operating costs	99,188		19,515		38,720		244,494		19,515		237,546
Depreciation, depletion, and amortization	15,294		7,467		17,919		49,169		7,467		115,496
Impairments (Note 3)	—		13,237		16,572		—		13,237		867,814
Loss on abandonment of assets (Note 3)	—		—		1,179		—		—		18,733
General and administrative	5,126		1,582		5,399		18,046		1,582		42,766
Gain on disposition of assets	( 4,031 )		( 222 )		( 1,356 )		( 6,213 )		( 222 )		( 89 )
Total operating expenses	115,577		41,579		78,433		305,496		41,579		1,282,266
Income (loss) from operations	47,671		( 8,733 )		( 12,859 )		112,706		( 8,733 )		( 1,005,309 )
Other income (expense):
Interest, net (excludes interest expense of $ 5.4 million on senior subordinated notes subject to compromise, for the two and eight months ended August 31, 2020)	( 702 )		( 826 )		( 1,959 )		( 3,895 )		( 826 )		( 22,824 )
Write-off of debt issuance costs	—		—		—		—		—		( 2,426 )
Gain (loss) on derivatives (Note 12)	( 39,742 )		3,939		( 4,250 )		( 104,973 )		3,939		( 10,704 )
Loss on change in fair value of warrants (Note 13)	( 9,054 )		—		—		( 12,628 )		—		—
Reorganization items, net	( 971 )		( 1,155 )		141,002		( 3,959 )		( 1,155 )		133,975
Other, net	( 7 )		39		1,931		( 762 )		39		2,034
Total other income (expense)	( 50,476 )		1,997		136,724		( 126,217 )		1,997		100,055
Income (loss) before income taxes	( 2,805 )		( 6,736 )		123,865		( 13,511 )		( 6,736 )		( 905,254 )
Income tax benefit:
Current	—		—		—		—		—		( 917 )
Deferred	—		—		( 4,750 )		—		—		( 13,713 )
Total income taxes	—		—		( 4,750 )		—		—		( 14,630 )
Net income (loss)	( 2,805 )		( 6,736 )		128,615		( 13,511 )		( 6,736 )		( 890,624 )
Net income (loss) attributable to non-controlling interest	( 9,100 )		2,232		73,484		( 4,875 )		2,232		40,388
Net income (loss) attributable to Unit Corporation	$	6,295	$	( 8,968 )	$	55,131	$	( 8,636 )	$	( 8,968 )	$	( 931,012 )
Net income (loss) attributable to Unit Corporation per common share (Note 7):
Basic	$	0.56	$	( 0.75 )	$	1.03	$	( 0.74 )	$	( 0.75 )	$	( 17.45 )
Diluted	$	0.55	$	( 0.75 )	$	1.03	$	( 0.74 )	$	( 0.75 )	$	( 17.45 )

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)


	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)	—		—		—		( 1,937 )		1,346		( 591 )
Activity in stock-based compensation plans	—		—		74		—		16		90
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
Net income (loss) (1)	—		—		—		6,295		( 9,100 )		( 2,805 )
Balance correction (Note 2)	—		—		—		( 1,437 )		1,437		—
Activity in stock-based compensation plans	—		—		( 82 )		—		—		( 82 )
Distributions to non-controlling interests	—		—		—		—		( 3,834 )		( 3,834 )
Repurchase of common stock	—		( 10,834 )		—		—		—		( 10,834 )
Balances, September 30, 2021 (Successor)	$	120	$	( 19,882 )	$	197,479	$	( 28,213 )	$	226,786	$	376,290

_______________________

1. Includes a one-time adjustment to correct an error discovered in our second quarter 2021 allocation of earnings from consolidated subsidiaries, as described in Note 2 - Summary Of Significant Accounting Policies.

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


	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, 2019 (Predecessor)	$	10,591	$	—	$	644,152	$	199,135	$	201,757	$	1,055,635
Net loss	—		—		—		( 770,494 )		( 33,180 )		( 803,674 )
Activity in stock-based compensation plans	103		—		2,391		—		31		2,525
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
Net income	—		—		—		55,131		73,484		128,615
Activity in stock-based compensation plans	—		—		2,025		—		8		2,033
Balances, August 31, 2020 (Predecessor)	10,704		—		650,153		( 731,877 )		242,200		171,180
Cancellation of predecessor equity	( 10,704 )		—		( 650,153 )		731,877		—		71,020
Issuance of successor common stock	120		—		197,203		—		—		197,323
Balances, September 1, 2020 (Successor)	120		—		197,203		—		242,200		439,523
Net income (loss)	—		—		—		( 8,968 )		2,232		( 6,736 )
Activity in stock-based compensation plans	—		—		9		—		4		13
Balances, September 30, 2020 (Successor)	$	120	$	—	$	197,212	$	( 8,968 )	$	244,436	$	432,800

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		Successor		Predecessor
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
OPERATING ACTIVITIES:	(In thousands)
Net loss	$	( 13,511 )	$	( 6,736 )	$	( 890,624 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	49,169		7,467		115,496
Impairments (Note 3)	—		13,237		867,814
Loss on abandonment of assets (Note 3)	—		—		18,733
Amortization of debt issuance costs and debt discount	—		—		1,079
Loss on derivatives (Note 12)	104,973		( 3,939 )		10,704
Cash payments on derivatives settled (Note 12)	( 22,647 )		( 1,418 )		( 4,244 )
Loss on change in fair value of warrants (Note 13)	12,628		—		—
Gain on disposition of assets	( 6,213 )		( 222 )		( 89 )
Write-off of debt issuance costs	—		—		2,426
Deferred tax expense	—		—		( 13,713 )
Stock-based compensation plans	268		13		4,786
Credit loss expense	1,695		—		3,155
ARO liability accretion (Note 10)	1,381		116		1,545
Contract assets and liabilities, net (Note 4)	2,462		324		2,459
Capitalized contract fulfillment costs, net	( 353 )		—		—
Noncash reorganization items	( 67 )		1,024		( 138,797 )
Other, net	( 1,950 )		( 2,623 )		12,164

Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	( 16,255 )		( 2,202 )		28,880
Material and supplies	—		—		89
Prepaid expenses and other	1,063		194		( 3,849 )
Accounts payable	12,350		2,366		( 18,381 )
Accrued liabilities	( 1,607 )		2,082		44,811
Income taxes	1,128		—		906
Contract advances	( 88 )		( 9 )		( 394 )

Net cash provided by (used in) operating activities	124,426		9,674		44,956
INVESTING ACTIVITIES:
Capital expenditures	( 21,117 )		( 1,598 )		( 25,775 )
Producing properties and other acquisitions	—		—		( 382 )
Proceeds from disposition of property and equipment	71,350		576		6,018


Net cash provided by (used in) investing activities	50,233		( 1,022 )		( 20,139 )
FINANCING ACTIVITIES:
Borrowings under line of credit, including borrowings under DIP credit facility	30,700		—		87,400
Payments under line of credit	( 126,600 )		( 4,000 )		( 64,100 )
DIP financing costs	—		—		( 990 )

Exit facility financing costs	—		—		( 3,225 )
Net payments on finance leases	( 3,216 )		( 350 )		( 2,757 )
Employee taxes paid by withholding shares	—		—		( 43 )





Distributions to non-controlling interests	( 16,178 )		—		—
Repurchase of common stock	( 19,882 )		—		—
Bank overdrafts	( 2,631 )		—		( 8,733 )
Net cash provided by (used in) financing activities	( 137,807 )		( 4,350 )		7,552
Net increase (decrease) in cash, restricted cash and cash equivalents	36,852		4,302		32,369
Cash, restricted cash, and cash equivalents, beginning of period	12,714		32,940		571
Cash, restricted cash, and cash equivalents, end of period	$	49,566	$	37,242	$	32,940

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		Successor		Predecessor
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
	(In thousands)
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Interest paid	$	4,307	$	251	$	6,417
Income taxes	( 1,128 )		—		—
Reorganization items	4,026		131		4,822

Changes in accounts payable and accrued liabilities related to purchases of property and equipment	( 3,356 )		( 128 )		8,561
Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations	( 1,674 )		( 215 )		29,189
Non-cash trade of property and equipment	—		—		1,403

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 third quarter 2021, management identified an error in the allocation of earnings from Superior between Unit Corporation and non-controlling interests related to the three months ended June 30, 2021 as well as an unrelated error in the initial allocation of equity between Unit Corporation and non-controlling interests as of the Fresh Start Reporting Date. The impact of the errors were not material to any of our prior period financial statements and both errors were corrected with one-time adjustments in the three months ended September 30, 2021. As a result, during the three months ended September 30, 2021, net income (loss) attributable to Unit Corporation was increased by $ 12.2 million with a corresponding decrease to net income (loss) attributable to non-controlling interest, and retained earnings (deficit) was reduced by $ 1.4 million with a corresponding decrease to non-controlling interest in consolidated subsidiaries.

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 nine months ended September 30, 2021.

During the one month ended September 30, 2020, the application of the full cost accounting rules resulted in a pre-tax non-cash ceiling impairment of $ 13.2 million primarily due to the use of average 12-month historical commodity prices for the ceiling test compared to forward prices for the fresh start fair value estimates.

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 eight months ended August 31, 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 eight months ended August 31, 2020.

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Contract Drilling

There were no impairments recorded during the three and nine months ended September 30, 2021.

During the two months ended August 31, 2020, we recorded expense of $ 1.1 million related to the write-down of certain equipment that we consider abandoned. These amounts are reported in loss on abandonment of assets in our unaudited condensed consolidated statements of operations.

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 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 eight months ended August 31, 2020 or one month ended September 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 included forecasted utilization, gross margins, salvage values, discount rates, and terminal values. There were no additional triggering events identified during the eight months ended August 31, 2020 or one month ended September 30, 2020.

Mid-Stream

There were no impairments recorded during the three and nine months ended September 30, 2021. We will continue to monitor for potential impairment in the fourth quarter of 2021 as certain systems negotiate renewed terms with their current volume commitments nearing an end.

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 eight months ended August 31, 2020 or one month ended September 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.

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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 September 30, 2021, we had nine contract drilling contracts with remaining terms ranging from two to fifteen 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.

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	September 30, 2021		December 31, 2020		Change
		(In thousands)
Assets
Current contract assets	Prepaid expenses and other	$	1,700	$	6,084	$	( 4,384 )
Non-current contract assets	Other assets	—		173		( 173 )
Total contract assets		$	1,700	$	6,257	$	( 4,557 )

Liabilities
Current contract liabilities	Current portion of other long-term liabilities	$	1,919	$	2,583	$	( 664 )
Non-current contract liabilities	Other long-term liabilities	158		1,589		( 1,431 )
Total contract liabilities		2,077		4,172		( 2,095 )
Contract assets (liabilities), net		$	( 377 )	$	2,085	$	( 2,462 )

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 September 30, 2021.


Contract	Remaining Term of Contract	2021		2022		2023 and beyond		Total Remaining Impact to Revenue
		(In thousands)
Demand fee contracts	1 - 13 months	$	( 997 )	$	1,374	$	—	$	377

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NOTE 5 – DIVESTITURES

Oil and Natural Gas

The company initiated an asset divestiture program at the beginning of 2021 to sell certain non-core oil and gas properties and reserves (the “Divestiture Program”). On October 4, 2021, the company announced that it is expanding the Divestiture Program to now include the potential sale of additional properties, including up to all of UPC’s oil and gas properties and reserves. The company expects to enhance various severance and certain other related benefits in response to the Divestiture Program.

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

On March 30, 2021, the company entered into a purchase and sale agreement in 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 $ 5.0 million of other non-core oil and natural gas assets, net of related expenses, during the nine months ended September 30, 2021, compared to $ 1.2 million during the eight months ended August 31, 2020 and none during the one month ended September 30, 2020. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.

Contract Drilling

We sold non-core contract drilling assets for proceeds of $ 4.3 million and $ 8.2 million, net of related expenses, during the three and nine months ended September 30, 2021, compared to $ 2.0 million and $ 4.8 million during the two and eight months ended August 31, 2020, and $ 0.6 million during the one month ended September 30, 2020. These proceeds resulted in net gains of $ 3.1 million and $ 5.2 million during the three and nine months ended September 30, 2021, compared to $ 1.3 million and $ 1.4 million during the two and eight months ended August 31, 2020, and $ 0.2 million during the one month ended September 30, 2020.

Corporate and Other

On September 17, 2021, we closed the sale of our corporate headquarters building and land for $ 35.0 million, subject to customary closing and post-close adjustments resulting in a gain of $ 0.9 million net of $ 2.2 million of transaction costs. In conjunction with the closing, we entered into a multi-year lease for a portion of the building.

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 unaudited condensed consolidated balance sheets as of September 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. In October 2021, the Board authorized an increase from $ 25.0 million of authorized repurchases to $ 50.0 million. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. 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 September 30, 2021, the company has repurchased a total of 350,037 shares at an average share price of $ 26.70 for an aggregate purchase price of $ 9.3 million under the repurchase program.

During the three months ended September 30, 2021, the company also repurchased 78,000 shares at a share price of $ 19.07 which were not part of the repurchase program.

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Subsequent to September 30, 2021, the company repurchased an additional 711,926 shares under the repurchase program at an average share price of $ 34.80 for an aggregate purchase price of $ 24.8 million bringing the aggregate shares repurchased under all methods since the Effective Date to 1,739,963 shares.

NOTE 7 – EARNINGS (LOSS) PER SHARE

Information related to the calculation of earnings (loss) per share attributable to Unit Corporation for the three months ended September 30, 2021, one month ended September 30, 2020, and two months ended August 31, 2020 is as follows:


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended September 30, 2021 (Successor)
Basic earnings attributable to Unit Corporation per common share	$	6,295	11,311	$	0.56
Effect of dilutive restricted stock	—		109	( 0.01 )
Diluted earnings attributable to Unit Corporation per common share	$	6,295	11,420	$	0.55
For the one month ended September 30, 2020 (Successor)
Basic loss attributable to Unit Corporation per common share	$	( 8,968 )	12,000	$	( 0.75 )
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	( 8,968 )		12,000	$	( 0.75 )
For the two months ended August 31, 2020 (Predecessor)
Basic earnings attributable to Unit Corporation per common share	$	55,131	53,519	$	1.03
Effect of dilutive stock options and restricted stock	—		—	—
Diluted earnings attributable to Unit Corporation per common share	$	55,131	53,519	$	1.03

Information related to the calculation of earnings (loss) per share attributable to Unit Corporation for the nine months ended September 30, 2021 and eight months ended August 31, 2020 is as follows:


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the nine months ended September 30, 2021 (Successor)
Basic loss attributable to Unit Corporation per common share	$	( 8,636 )	11,735	$	( 0.74 )
Effect of dilutive restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	( 8,636 )	11,735	$	( 0.74 )
For the eight months ended August 31, 2020 (Predecessor)
Basic loss attributable to Unit Corporation per common share	$	( 931,012 )	53,368	$	( 17.45 )
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	( 931,012 )	53,368	$	( 17.45 )

Because of the net loss for the nine months ended September 30, 2021, approximately 62,690 weighted average shares of restricted stock were antidilutive and were excluded from the earnings per share calculation above.

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NOTE 8 – ACCRUED LIABILITIES

Accrued liabilities consisted of:



	September 30, 2021		December 31, 2020
	(In thousands)
Employee costs	$	7,692	$	8,878
Lease operating expenses	3,792		6,405
Capital expenditures	6,998		3,461
Taxes	6,576		2,324
Interest payable	402		884
Legal settlement	—		2,070
Other	1,519		1,182
Total accrued liabilities	$	26,979	$	25,204

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:


	September 30, 2021		December 31, 2020
	(In thousands)
Current portion of long-term debt:
Exit credit agreement with an average interest rate of 6.6 % at December 31, 2020	$	—	$	600
Long-term debt:
Exit credit agreement with an average interest rate of 6.6 % at December 31, 2020	$	—	$	98,400
Superior credit agreement with an average interest rate of 2.1 % at September 30, 2021	$	3,100	$	—

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.

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

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 and September 30, 2021, to be greater than 3.75 to 1.00, and (iii) December 31, 2021 and any fiscal quarter thereafter, to be greater than 3.25 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 to 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 September 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 September 30, 2021, we had no long-term borrowings and $ 3.2 million of letters of credit outstanding under the Exit credit agreement.

Superior Credit Agreement. On May 10, 2018, Superior signed a five-year , $ 200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $ 250.0 million, subject to certain conditions (Superior credit agreement). The maturity date of borrowings under the Superior credit agreement is March 10, 2023. The amounts borrowed under the Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) the Thirty-Day LIBOR Rate (as defined in the Superior credit agreement)) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by mortgage liens on certain of Superior’s processing plants and gathering systems. The Superior credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to the Administrative Agent in the London Interbank Market, the Administrative Agent may select a replacement index.

Superior is charged a commitment fee of 0.375 % on the amount available but not borrowed which varies based on the amount borrowed as a percentage of the total borrowing base.

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 September 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 September 30, 2021, we had $ 3.1 million of 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.

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Other Long-Term Liabilities

Other long-term liabilities consisted of the following:



	September 30, 2021		December 31, 2020
	(In thousands)
Asset retirement obligation (ARO) liability	$	26,372	$	23,356
Workers’ compensation	11,311		10,164
Finance lease obligations	—		3,216
Contract liability	2,077		4,172
Separation benefit plans	2,675		4,201
Gas balancing liability	4,238		3,997
Other long-term liability	1,323		1,321
	47,996		50,427
Less: current portion	6,522		11,168
Total other long-term liabilities	$	41,474	$	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.

The following table shows certain information about our estimated AROs for the periods indicated (in thousands):


ARO liability, December 31, 2020 (Successor):	$	23,356
Accretion of discount	1,381
Liability incurred	4
Liability settled	( 852 )
Liability sold	( 1,925 )
Revision of estimates (1)	4,408
ARO liability, September 30, 2021 (Successor):	26,372
Less: current portion	2,455
Total long-term ARO	$	23,917

_______________________

1. Plugging liability estimates were revised in 2021 for updates in the cost of services used to plug wells over the preceding year as well as estimated inflation and discount rates. We had various upward and downward adjustments.

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ARO liability, December 31, 2019 (Predecessor)	$	66,627
Accretion of discount	1,545
Liability incurred	465
Liability settled	( 838 )
Liability sold	( 487 )
Revision of estimates (1)	( 28,328 )
ARO liability, August 31, 2020 (Predecessor)	38,984
Fresh start adjustments	( 14,393 )
ARO liability, August 31, 2020 (Successor)	24,591
Accretion of discount	116
Liability incurred	141
Liability settled	( 51 )
Liability sold	—
Revision of estimates	125
ARO liability, September 30, 2020 (Successor)	24,922
Less current portion	2,186
Total long-term ARO	$	22,736

_______________________

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.

On April 27, 2021, 109,008 aggregate restricted stock units (RSUs) 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 RSUs will 25% vest on each of the following dates: the date that is thirteen months following the date of grant, September 3, 2022, September 3, 2023, and September 3, 2024. The fair value of these grants is measured based on the closing stock price on grant date and compensation expense recognized in general and administrative on the unaudited condensed consolidated statements of operations over the vesting period. There were no other grants made during the nine months ended September 30, 2021.

No stock options or restricted stock units were granted during the two or eight months ended August 31, 2020, or during the one month ended September 30, 2020.

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.

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There were no outstanding restricted stock awards or stock options during the one month ended September 30, 2020. For the other periods, we had:


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30, 2021		Two Months Ended August 31, 2020		Nine Months Ended September 30, 2021		Eight Months Ended August 31, 2020
	(In millions)
Recognized stock compensation expense	$	( 0.1 )	$	2.0	$	0.1	$	6.1

Tax benefit on stock-based compensation	—		$	0.5	—		$	1.5

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 September 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 gain (loss) on derivatives in our unaudited condensed consolidated statements of operations.

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

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Oct'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$( 0.22 )

NGPL TEXOK

Oct'21

Natural gas - swap

50,000 MMBtu/day

$ 2.82

IF - NYMEX (HH)

Nov'21 - Dec'21

Natural gas - swap

45,000 MMBtu/day

$ 2.90

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - swap

5,000 MMBtu/day

$ 2.61

IF - NYMEX (HH)

Jan'23 - Dec'23

Natural gas - swap

22,000 MMBtu/day

$ 2.46

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - collar

35,000 MMBtu/day

$ 2.50 - $ 2.68

IF - NYMEX (HH)

Oct'21 - Dec'21

Crude oil - swap

3,373 Bbl/day

$ 45.14

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

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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	September 30, 2021		December 31, 2020
		(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	59,962	$	1,047
Long-term	Non-current derivative liability	28,069		4,659
Total derivative liabilities		$	88,031	$	5,706

All our counterparties are subject to master netting arrangements. If we have a legal right of set-off, we net the value of the derivative transactions we have with the same counterparty in our unaudited condensed consolidated balance sheets.

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


	Successor		Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30, 2021		One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Nine Months Ended September 30, 2021		Eight Months Ended August 31, 2020

	(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $( 12,940 ), $( 1,418 ), $( 3,552 ), $( 22,647 ), and $( 4,244 ), respectively	$	( 39,742 )	$	3,939	$	( 4,250 )	$	( 104,973 )	$	( 10,704 )
	$	( 39,742 )	$	3,939	$	( 4,250 )	$	( 104,973 )	$	( 10,704 )

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:



	September 30, 2021
	Level 2		Level 3		Effect of Netting		Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	—	$	—	$	—	$	—
Liabilities	( 88,031 )		—		—		( 88,031 )
Total commodity derivatives	$	( 88,031 )	$	—	$	—	$	( 88,031 )



	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 September 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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There was no Level 3 commodity derivative activity during the three or nine months ended September 30, 2021, or during the one month ended September 30, 2020. The following table is a reconciliation of our Level 3 commodity derivative fair value measurements for the two and eight months ended August 31, 2020:


		Predecessor
		Two Months Ended August 31, 2020		Eight Months Ended August 31, 2020

	(In thousands)
Beginning of period		$	843	$	1,204
Total gains or losses (realized and unrealized):
Included in earnings (1)		( 405 )		872
Settlements		( 438 )		( 2,076 )
End of period		$	—	$	—
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		$	( 843 )	$	( 1,204 )

_______________________

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

Our valuation at September 30, 2021 and December 31, 2020 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 $ 13.5 million and $ 0.9 million as of September 30, 2021 and December 31, 2020, respectively, with the increases of $ 4.8 million and $ 8.3 million for the three and nine months ended September 30, 2021, respectively, 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 September 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.

During the three months ended September 30, 2021, we entered into an operating lease agreement for our headquarters office space which generated right of use assets and liabilities at lease inception of $8.4 million.

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The following table sets forth the maturity of our operating lease liabilities as of September 30, 2021:


	Amount
	(In thousands)
Ending September 30,
2022	$	5,017
2023	3,339
2024	2,968
2025	2,095
2026	2,002
2027 and beyond	54
Total future payments	15,475
Less: Interest	1,689
Present value of future minimum operating lease payments	13,786
Less: Current portion	4,399
Total long-term operating lease payments	$	9,387

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	September 30, 2021		December 31, 2020
		(In thousands)
Assets
Operating right of use assets	Right of use assets	$	13,800	$	5,592
Finance right of use assets	Property, plant, and equipment, net	—		7,281
Total right of use assets		$	13,800	$	12,873

Liabilities
Current liabilities:
Operating lease liabilities	Current operating lease liabilities	$	4,399	$	4,075
Finance lease liabilities	Current portion of other long-term liabilities	—		3,216
Non-current liabilities:
Operating lease liabilities	Operating lease liabilities	9,387		1,445
Finance lease liabilities	Other long-term liabilities	—		—
Total lease liabilities		$	13,786	$	8,736

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



	Successor		Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30, 2021		One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Nine Months Ended September 30, 2021		Eight Months Ended August 31, 2020
	(In thousands)
Components of total lease cost:
Amortization of finance leased assets	$	—	$	350	$	696	$	1,248	$	2,757
Interest on finance lease liabilities	—		15		35		33		165
Operating lease cost	1,043		328		965		3,053		3,604
Short-term lease cost (1)	3,120		867		1,448		7,893		8,190
Variable lease cost	—		29		58		—		223
Total lease cost	$	4,163	$	1,589	$	3,202	$	12,227	$	14,939

_______________________

1. Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $ 0.8 million, $ — million , $ 0.1 million, $ 1.0 million, and $ 1.5 million for the three months ended September 30, 2021, the one month ended September 30, 2020, the two months ended August 31, 2020, the nine months ended September 30, 2021, and eight months ended August 31, 2020, respectively.

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


	Successor		Successor		Predecessor
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
	(In thousands)
Cash paid for amounts in the measurement of lease liabilities:
Operating cash flows for operating leases	$	3,125	$	351	$	3,849
Financing cash flows for finance leases	$	3,216	$	350	$	2,757

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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

3.9

5.51 %

_______________________

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 $ 1.1 million over the next twelve months and $ 0.1 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 (Drilling Commitment Amount) to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. If we do not spend all of the Drilling Commitment Amount, SP Investor receives 100% of cash distributions until the Drilling Commitment Adjustment Amount (as defined in the Amended and Restated Limited Liability Company Agreement (Agreement)) is satisfied. The total amount spent towards the $ 150.0 million as of September 30, 2021 was $ 24.8 million. At September 30, 2021, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount of the Drilling Commitment Adjustment Amount would be $ 72.6 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 Compan y 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.

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. Under the Plan, these settlements will be treated as allowed general unsecured claims against UPC. This settlement has been approved 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. and, in accordance with the Plan, the settlement amounts have been 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 Agreement and a Management Services Agreement (MSA). The MSA is between our wholly-owned subsidiary, SPC Midstream Operating, L.L.C. (the Operator) and Superior. As the Operator, we provide services, such as operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $ 0.3 million. 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 not receiving cash distributions proportionate to 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 before December 31, 2021 as 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. At September 30, 2021, liquidation distributions first paid to SP Investor of $ 362.6 million would be required for SP Investor to reach its 7 % Liquidation IRR Hurdle at which point Unit would then be entitled to receive up to $ 362.6 million of the remaining liquidation distributions to satisfy Unit's 7 % Liquidation IRR Hurdle with any remaining liquidation distributions paid as outlined within the Agreement. 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 allocate Unit's and SP Investor's share of earnings and losses from Superior in our unaudited condensed consolidated statement of operations using the hypothetical liquidation at book value (HLBV) method of accounting which is a balance-sheet approach that calculates the change in the hypothetical amount Unit and SP Investor would be entitled to receive if Superior were liquidated at book value at the end of each period, adjusted for any contributions made and distributions received during the period. 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 September 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.

On November 1, 2021, Superior acquired gas gathering and processing assets including a cryogenic processing plant and approximately 1,620 miles of low-pressure gathering pipeline along with related compressor stations and meters located in southern Kansas for $ 13.0 million, subject to customary closing and post-closing adjustments.

Superior paid cash distributions totaling $ 24.7 million in April 2021 related to cumulative available cash as of March 31, 2021, $ 7.7 million in July 2021 related to available cash generated during the three months ended June 30, 2021, and $ 13.9 million in October 2021 related to available cash generated during the three months ended September 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.


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

Current assets:
Cash and cash equivalents	$	12,286	$	11,642
Accounts receivable	36,487		27,427
Prepaid expenses and other	2,540		6,746
Total current assets	51,313		45,815
Property and equipment:
Gas gathering and processing equipment	259,642		251,403
Transportation equipment	2,086		1,748
	261,728		253,151
Less accumulated depreciation, depletion, amortization, and impairment	34,878		10,466
Net property and equipment	226,850		242,685
Right of use asset	3,926		2,823
Other assets	1,961		2,309
Total assets	$	284,050	$	293,632

Current liabilities:
Accounts payable	$	26,921	$	17,045
Accrued liabilities	6,441		3,777
Current operating lease liability	1,570		1,762
Current portion of other long-term liabilities	1,919		5,799
Total current liabilities	36,851		28,383
Long-term debt	3,100		—
Operating lease liability	2,356		1,013
Other long-term liabilities	158		1,589
Total liabilities	$	42,465	$	30,985

NOTE 17 – INCOME TAXES

For the three and nine months ended September 30, 2021, the company’s effective income tax rate was 0.0 % compared to ( 3.8 )% and 1.6 % for the two and eight months ended August 31, 2020, and 0.0 % for the one month ended September 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 21.0 % 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 September 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 or disposition, 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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Net Operating Loss

As of September 30, 2021, and after consideration of the tax attribute reductions of IRC Section 108 and finalization of the company’s 2020 federal income tax return, the company has an expected federal net operating loss carryforward of $ 420.3 million of which $ 225.3 million is subject to expiration between 2021 and 2037.

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.

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


	Successor
	Three Months Ended September 30, 2021
	Oil and Natural Gas		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	66,202	$	—	$	—	$	—	$	( 13,322 )	$	52,880
Contract drilling	—		19,158		—		—		—		19,158
Gas gathering and processing	—		—		92,022		—		( 812 )		91,210
Total revenues	66,202		19,158		92,022		—		( 14,134 )		163,248
Expenses:
Operating costs:
Oil and natural gas	22,022		—		—		—		( 812 )		21,210
Contract drilling	—		15,357		—		—		—		15,357
Gas gathering and processing	—		—		76,823		—		( 14,202 )		62,621
Total operating costs	22,022		15,357		76,823		—		( 15,014 )		99,188
Depreciation, depletion, and amortization	5,311		1,576		8,143		264		—		15,294

Total expenses	27,333		16,933		84,966		264		( 15,014 )		114,482

General and administrative	—		—		—		4,246		880		5,126
Gain on disposition of assets	( 14 )		( 3,091 )		—		( 926 )		—		( 4,031 )
Income (loss) from operations	38,883		5,316		7,056		( 3,584 )		—		47,671
Loss on derivatives	—		—		—		( 39,742 )		—		( 39,742 )
Loss on change in fair value of warrants	—		—		—		( 9,054 )		—		( 9,054 )

Reorganization items, net	—		—		—		( 971 )		—		( 971 )
Interest, net	—		—		( 250 )		( 452 )		—		( 702 )
Other	51		( 34 )		( 24 )		—		—		( 7 )
Income (loss) before income taxes	$	38,934	$	5,282	$	6,782	$	( 53,803 )	$	—	$	( 2,805 )

_______________________

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
	One Month Ended September 30, 2020
	Oil and Natural Gas		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	13,644	$	—	$	—	$	—	$	( 1 )	$	13,643
Contract drilling	—		4,414		—		—		—		4,414
Gas gathering and processing	—		—		17,284		—		( 2,495 )		14,789
Total revenues	13,644		4,414		17,284		—		( 2,496 )		32,846
Expenses:
Operating costs:
Oil and natural gas	6,892		—		—		—		( 218 )		6,674
Contract drilling	—		2,989		—		—		—		2,989
Gas gathering and processing	—		—		12,130		—		( 2,278 )		9,852
Total operating costs	6,892		2,989		12,130		—		( 2,496 )		19,515
Depreciation, depletion, and amortization	4,199		526		2,658		84		—		7,467
Impairments	13,237		—		—		—		—		13,237
Total expenses	24,328		3,515		14,788		84		( 2,496 )		40,219
General and administrative	—		—		—		1,582		—		1,582
Gain on disposition of assets	( 10 )		( 212 )		—		—		—		( 222 )
Income (loss) from operations	( 10,674 )		1,111		2,496		( 1,666 )		—		( 8,733 )
Gain on derivatives	—		—		—		3,939		—		3,939
Reorganization items, net	—		—		—		( 1,155 )		—		( 1,155 )
Interest, net	—		—		( 137 )		( 689 )		—		( 826 )
Other	29		1		8		1		—		39
Income (loss) before income taxes	$	( 10,645 )	$	1,112	$	2,367	$	430	$	—	$	( 6,736 )

_______________________

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

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	Predecessor
	Two Months Ended August 31, 2020
	Oil and Natural Gas		Contract Drilling		Mid-Stream			Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	27,962	$	—	$	—		$	—	$	( 1 )	$	27,961
Contract drilling	—		7,685		—			—		—		7,685
Gas gathering and processing	—		—		34,132			—		( 4,204 )		29,928
Total revenues	27,962		7,685		34,132			—		( 4,205 )		65,574
Expenses:
Operating costs:
Oil and natural gas	15,895		—		—			—		( 407 )		15,488
Contract drilling	—		5,410		—			—		—		5,410
Gas gathering and processing	—		—		21,620			—		( 3,798 )		17,822
Total operating costs	15,895		5,410		21,620			—		( 4,205 )		38,720
Depreciation, depletion, and amortization	9,975		853		6,750			341		—		17,919
Impairments	16,572		—		—			—		—		16,572
Total expenses	42,442		6,263		28,370			341		( 4,205 )		73,211
Loss on abandonment of assets	87		1,092		—			—		—		1,179
General and administrative	—		—		—			5,399		—		5,399
Gain on disposition of assets	( 102 )		( 1,251 )		( 3 )		0	—		—		( 1,356 )
Income (loss) from operations	( 14,465 )		1,581		5,765			( 5,740 )		—		( 12,859 )
Loss on derivatives	—		—		—			( 4,250 )		—		( 4,250 )
Reorganization items, net	15,504		( 183,664 )		( 71,016 )			380,178		—		141,002
Interest, net	—		—		( 828 )			( 1,131 )		—		( 1,959 )
Other	428		1,426		11			66		—		1,931
Income (loss) before income taxes	$	1,467	$	( 180,657 )	$	( 66,068 )		$	369,123	$	—	$	123,865

_______________________

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
	Nine Months Ended September 30, 2021
	Oil and Natural Gas		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	181,003	$	—	$	—	$	—	$	( 31,129 )	$	149,874
Contract drilling	—		52,893		—		—		—		52,893
Gas gathering and processing	—		—		217,954		—		( 2,519 )		215,435
Total revenues	181,003		52,893		217,954		—		( 33,648 )		418,202
Expenses:
Operating costs:
Oil and natural gas	58,365		—		—		—		( 2,519 )		55,846
Contract drilling	—		41,308		—		—		—		41,308
Gas gathering and processing	—		—		181,109		—		( 33,769 )		147,340
Total operating costs	58,365		41,308		181,109		—		( 36,288 )		244,494
Depreciation, depletion, and amortization	19,442		4,721		24,238		768		—		49,169

Impairment	—		—		—		—		—		—
Total expenses	77,807		46,029		205,347		768		( 36,288 )		293,663


General and administrative	—		—		—		15,406		2,640		18,046
(Gain) loss on disposition of assets	( 101 )		( 5,237 )		75		( 950 )		—		( 6,213 )
Income (loss) from operations	103,297		12,101		12,532		( 15,224 )		—		112,706
Loss on derivatives	—		—		—		( 104,973 )		—		( 104,973 )

Loss on change in fair value of warrants	—		—		—		( 12,628 )		—		( 12,628 )
Reorganization items, net	—		—		—		( 3,959 )		—		( 3,959 )
Interest, net	—		—		( 666 )		( 3,229 )		—		( 3,895 )
Other	140		( 17 )		( 863 )		( 22 )		—		( 762 )
Income (loss) before income taxes	$	103,437	$	12,084	$	11,003	$	( 140,035 )	$	—	$	( 13,511 )

_______________________

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

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	Predecessor
	Eight Months Ended August 31, 2020
	Oil and Natural Gas		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	103,443	$	—	$	—	$	—	$	( 4 )	$	103,439
Contract drilling	—		73,519		—		—		—		73,519
Gas gathering and processing	—		—		114,531		—		( 14,532 )		99,999
Total revenues	103,443		73,519		114,531		—		( 14,536 )		276,957
Expenses:
Operating costs:
Oil and natural gas	119,664		—		—		—		( 1,973 )		117,691
Contract drilling	—		51,811		—		—		( 1 )		51,810
Gas gathering and processing	—		—		80,607		—		( 12,562 )		68,045
Total operating costs	119,664		51,811		80,607		—		( 14,536 )		237,546
Depreciation, depletion, and amortization	68,762		15,544		29,371		1,819		—		115,496
Impairments	393,726		410,126		63,962		—		—		867,814
Total expenses	582,152		477,481		173,940		1,819		( 14,536 )		1,220,856
Loss on abandonment of assets	17,641		1,092		—		—		—		18,733
General and administrative	—		—		—		42,766		—		42,766
(Gain) loss on disposition of assets	( 160 )		( 1,390 )		( 18 )		1,479		—		( 89 )
Loss from operations	( 496,190 )		( 403,664 )		( 59,391 )		( 46,064 )		—		( 1,005,309 )
Loss on derivatives	—		—		—		( 10,704 )		—		( 10,704 )
Write-off of debt issuance costs	—		—		—		( 2,426 )		—		( 2,426 )
Reorganization items, net	15,504		( 183,664 )		( 71,016 )		373,151		—		133,975
Interest, net	—		—		( 1,888 )		( 20,936 )		—		( 22,824 )
Other	458		1,449		50		77		—		2,034
Income (loss) before income taxes	$	( 480,228 )	$	( 585,879 )	$	( 132,245 )	$	293,098	$	—	$	( 905,254 )

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

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
	Two Months Ended August 31, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	35,647	$	34,132	$	( 4,205 )	$	65,574
Expenses:
Operating costs	—		21,307		21,619		( 4,206 )		38,720
Depreciation, depletion, and amortization	341		10,828		6,750		—		17,919
Impairments	—		16,572		—		—		16,572
Loss on abandonment of assets	—		1,179		—		—		1,179
General and administrative expense	—		5,399		—		—		5,399
Gain on disposition of assets	—		( 1,353 )		( 3 )		—		( 1,356 )
Total operating costs	341		53,932		28,366		( 4,206 )		78,433
Income (loss) from operations	( 341 )		( 18,285 )		5,766		1		( 12,859 )
Interest, net	( 1,131 )		—		( 828 )		—		( 1,959 )
Write-off of debt issuance costs	—		—		—		—		—
Loss on derivatives	( 4,250 )		—		—		—		( 4,250 )
Reorganization items	380,178		( 168,160 )		( 71,016 )		—		141,002
Other, net	68		1,853		10		—		1,931
Income (loss) before income taxes	374,524		( 184,592 )		( 66,068 )		1		123,865
Income tax benefit	( 4,750 )		—		—		—		( 4,750 )
Equity in net earnings from investment in subsidiaries, net of taxes	( 250,659 )		—		—		250,659		—
Net income (loss)	128,615		( 184,592 )		( 66,068 )		250,660		128,615
Less: net income attributable to non-controlling interest	73,484		—		73,484		( 73,484 )		73,484
Net income (loss) attributable to Unit Corporation	$	55,131	$	( 184,592 )	$	( 139,552 )	$	324,144	$	55,131

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	Predecessor
	Eight Months Ended August 31, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	176,962	$	114,531	$	( 14,536 )	$	276,957
Expenses:
Operating costs	—		171,476		80,607		( 14,537 )		237,546
Depreciation, depletion, and amortization	1,819		84,306		29,371		—		115,496
Impairments	—		803,852		63,962		—		867,814
Loss on abandonment of assets	—		18,733		—		—		18,733
General and administrative	—		42,766		—		—		42,766
(Gain) loss on disposition of assets	1,479		( 1,550 )		( 18 )		—		( 89 )
Total operating costs	3,298		1,119,583		173,922		( 14,537 )		1,282,266
Income (loss) from operations	( 3,298 )		( 942,621 )		( 59,391 )		1		( 1,005,309 )
Interest, net	( 20,936 )		—		( 1,888 )		—		( 22,824 )
Write-off of debt issuance costs	( 2,426 )		—		—		—		( 2,426 )
Loss on derivatives	( 10,704 )		—		—		—		( 10,704 )
Reorganization items	373,151		( 168,160 )		( 71,016 )		—		133,975
Other, net	79		1,906		49		—		2,034
Income (loss) before income taxes	335,866		( 1,108,875 )		( 132,246 )		1		( 905,254 )
Income tax benefit	( 14,630 )		—		—		—		( 14,630 )
Equity in net earnings from investment in subsidiaries, net of taxes	( 1,241,120 )		—		—		1,241,120		—
Net loss	( 890,624 )		( 1,108,875 )		( 132,246 )		1,241,121		( 890,624 )
Less: net income attributable to non-controlling interest	40,388		—		40,388		( 40,388 )		40,388
Net loss attributable to Unit Corporation	$	( 931,012 )	$	( 1,108,875 )	$	( 172,634 )	$	1,281,509	$	( 931,012 )

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Condensed Consolidating Statements of Cash Flows (Unaudited)


	Predecessor
	Eight Months Ended August 31, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	( 207,593 )	$	82,769	$	32,922	$	136,858	$	44,956
INVESTING ACTIVITIES:									—
Capital expenditures	( 986 )		( 14,585 )		( 10,204 )		—		( 25,775 )
Producing properties and other acquisitions	—		( 382 )		—		—		( 382 )
Proceeds from disposition of assets	1,169		4,772		77		—		6,018
Net cash provided by (used in) investing activities	183		( 10,195 )		( 10,127 )		—		( 20,139 )
FINANCING ACTIVITIES:
Borrowings under credit agreement, including borrowings under DIP credit facility	55,300		—		32,100		—		87,400
Payments under credit agreement	( 31,500 )		—		( 32,600 )		—		( 64,100 )
DIP financing costs	( 990 )		—		—		—		( 990 )
Exit facility financing costs	( 3,225 )		—		—		—		( 3,225 )
Intercompany borrowings (advances), net	210,398		( 72,642 )		( 898 )		( 136,858 )		—
Payments on finance leases	—		—		( 2,757 )		—		( 2,757 )
Employee taxes paid by withholding shares	( 43 )		—		—		—		( 43 )

Bank overdrafts	( 7,269 )		—		( 1,464 )		—		( 8,733 )
Net cash provided by (used in) financing activities	222,671		( 72,642 )		( 5,619 )		( 136,858 )		7,552
Net increase (decrease) in cash and cash equivalents	15,261		( 68 )		17,176		—		32,369
Cash and cash equivalents, beginning of period	503		68		—		—		571
Cash and cash equivalents, end of period	$	15,764	$	—	$	17,176	$	—	$	32,940

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

Introduction

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

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

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

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

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

In our oil and natural gas segment, we are optimizing production and converting non-producing reserves to producing, with selective drilling activities in core areas. At the beginning of 2021, the company initiated an asset divestiture program in UPC to sell certain non-core oil and gas properties and reserves. On October 4, 2021, the company announced the expansion of its divestiture efforts to now include the potential sale of additional properties, including up to all of UPC’s oil and gas properties and reserves. Management continues to identify and execute on low cost capital projects to enhance production and reserves in this favorable price environment.

In our contract drilling segment, management reduced the number of drilling rigs available for use from 58 at December 31, 2020 to 21 during the second quarter of 2021 in order to focus on utilization of our BOSS drilling rigs and certain SCR rigs that are either currently under contract or candidates for future upgrades. Of the 21 rigs available for use, 13 are currently working, 4 are actively being marketed, and the remaining 4 will be considered for upgrade and marketing as future conditions warrant. We also plan to continue seeking opportunities to divest non-core, idle drilling equipment.

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

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

Recent Developments

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. In October 2021, the Board authorized an increase from $25.0 million of authorized repurchases to $50.0 million. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. 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 September 30, 2021, the company has repurchased a total of 350,037 shares at an average share price of $26.70 for an aggregate purchase price of $9.3 million under the repurchase program.

Subsequent to September 30, 2021, the company repurchased an additional 711,926 shares under the repurchase program at an average share price of $34.80 for an aggregate purchase price of $24.8 million bringing the aggregate shares repurchased under all methods since the Effective Date to 1,739,963 shares.

Allocation of New Common Stock

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

Warrants

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

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


Issuance Date			Warrants Issued
December 21, 2020			1,770,552
February 11, 2021			42,511
July 29, 2021			10,521
October 13, 2021			5,005
Total			1,828,589

The company expects to issue approximately 14,729 more Warrants to the holders of the Old Common Stock that did not opt-out of the releases under the Plan and owned their shares through Direct Registration.

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Financial Condition and Liquidity

Summary

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

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

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

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

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

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

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


	Successor		Successor		Predecessor		Percent Change (1)
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
	(In thousands except percentages)
Net cash provided by (used in) operating activities	$	124,426	$	9,674	$	44,956	128	%
Net cash provided by (used in) investing activities	50,233		(1,022)		(20,139)		NM
Net cash provided by (used in) financing activities	(137,807)		(4,350)		7,552		NM
Net increase (decrease) in cash, restricted cash and cash equivalents	$	36,852	$	4,302	$	32,369

_________________________

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 (used in) operating activities in the first nine months of 2021 increased by $69.8 million as compared to the first nine 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 low cost capital projects to enhance production and reserves in this favorable price environment.

Net cash provided by (used in) investing activities increased by $71.4 million for the first nine months of 2021 compared to the first nine months of 2020. The change was primarily due to proceeds received from the disposition of our corporate headquarters building and land, an increase in proceeds received from the disposition of other non-core assets, and a decrease in capital expenditures resulting from a decrease in the number of wells drilled and oil and gas property acquisitions.

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Cash Flows from Financing Activities

Net cash provided by (used in) financing activities decreased by $141.0 million for the first nine months of 2021 compared to the first nine months of 2020. The decrease was primarily due to higher payments on our credit agreements, lower net borrowings under our credit agreements, distributions made to non-controlling interests, the repurchase of common stock, and lower bank overdrafts.

At September 30, 2021, we had unrestricted cash and cash equivalents totaling $49.6 million, which includes $12.3 million of cash and cash equivalents held by Superior, and $3.1 million of outstanding borrowings, all of which was borrowed under the Superior credit agreement. Unit had no outstanding borrowings under the Exit credit agreement.

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


	Successor		Successor
	2021		2020
	(In thousands)
Working capital	$	(30,367)	$	21,624
Current portion of long-term debt	$	—	$	400
Long-term debt	$	3,100	$	143,600
Shareholders’ equity attributable to Unit Corporation	$	149,504	$	188,364

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 $30.4 million and positive working capital of $21.6 million as of September 30, 2021 and 2020, respectively. The decrease in working capital is primarily due to higher current derivative liabilities, warrant liability, and accounts payable, partially offset by increases in cash and cash equivalents and accounts receivable. The effect of our derivative contracts decreased working capital by $60.0 million as of September 30, 2021 and increased working capital by $1.3 million as of September 30, 2020.

Our Credit Agreements

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

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

At September 30, 2021, we had $3.1 million outstanding long-term borrowings under the Exit credit agreement. During the nine month period ended September 30, 2021, the company repaid $126.6 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.

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

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

Capital expenditures for oil and gas properties on the full cost method for the first nine months of 2021 by this segment, excluding a $1.6 million increase in the ARO liability, totaled $7.1 million. Capital expenditures for the first nine months of 2020, excluding $0.4 million for acquisitions and a $28.2 million reduction in the ARO liability, totaled $10.3 million.

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

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

We sold $5.0 million of other non-core oil and natural gas assets, net of related expenses, during the nine months ended September 30, 2021, compared to $1.2 million during the eight months ended August 31, 2020 and none during the one month ended September 30, 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 $0.9 million in capital expenditures during the first nine months of 2021, compared to $4.0 million for capital expenditures during the first nine months of 2020.

We sold non-core contract drilling assets for proceeds of $8.2 million, net of related expenses, during the nine months ended September 30, 2021, compared to proceeds of $4.8 million during the eight months ended August 31, 2020 and none during the one month ended September 30, 2020. These proceeds resulted in net gains of $5.2 million during the nine months ended September 30, 2021, compared to $1.4 million during the eight months ended August 31, 2020.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures . During the first nine months of 2021, our mid-stream segment incurred $8.6 million in capital expenditures as compared to $10.2 million in the first nine months of 2020. For 2021, we estimate total capital expenditures of approximately $24.2 million, primarily for the gas gathering and processing assets acquired in November 2021 as well as 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 September 30, 2021, based on our third quarter 2021 average daily production, the approximated percentages of our production under derivative contracts are as follows:


	2021	2022	2023
Daily oil production	87%	64%	36%
Daily natural gas production	63%	54%	30%

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 September 30, 2021 evaluation, we believe the risk of non-performance by our counterparties is not material. At September 30, 2021, the fair values of the net liabilities we had with each of the counterparties to our commodity derivative transactions are as follows:


	September 30, 2021
	(In thousands)
Bank of Oklahoma	$	(87,826)
Bank of Montreal	(205)
Total net liabilities	$	(88,031)

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


	Successor		Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30, 2021		One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Nine Months Ended September 30, 2021		Eight Months Ended August 31, 2020

	(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $(12,940), $(1,418), $(3,552), $(22,647), and $(4,244), respectively	$	(39,742)	$	3,939	$	(4,250)	$	(104,973)	$	(10,704)
	$	(39,742)	$	3,939	$	(4,250)	$	(104,973)	$	(10,704)

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Results of Operations

Quarter Ended September 30, 2021 versus Quarter Ended September 30, 2020

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


	Successor			Successor			Predecessor			Percent Change (1)
	Quarter Ended September 30, 2021			One Month Ended September 30, 2020			Two Months Ended August 31, 2020
	(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations	$	177,382		$	35,342		$	69,779		69	%
Total revenue, after inter-segment eliminations	$	163,248		$	32,846		$	65,574		66	%
Net income (loss)	$	(2,805)		$	(6,736)		$	128,615		(102)	%
Net income (loss) attributable to non-controlling interest	$	(9,100)		$	2,232		$	73,484		(112)	%
Net income (loss) attributable to Unit Corporation	$	6,295		$	(8,968)		$	55,131		(86)	%

Oil and Natural Gas:
Revenue, before inter-segment eliminations	$	66,202		$	13,644		$	27,962		59	%
Operating costs, before inter-segment eliminations	$	22,022		$	6,892		$	15,895		(3)	%
Average oil price (Bbl)	$	47.66		$	28.11		$	28.64		67	%
Average oil price excluding derivatives (Bbl)	$	70.53		$	36.94		$	38.55		86	%
Average NGLs price (Bbl)	$	27.42		$	7.47		$	8.53		NM
Average NGLs price excluding derivatives (Bbl)	$	27.42		$	7.47		$	8.53		NM
Average natural gas price (Mcf)	$	2.88		$	1.72		$	1.07		125	%
Average natural gas price excluding derivatives (Mcf)	$	3.69		$	1.70		$	1.10		186	%
Oil production (MBbls)	329			167			341			(35)	%
NGL production (MBbls)	649			273			572			(23)	%
Natural gas production (MMcf)	6,805			2,849			6,184			(25)	%


Contract Drilling:
Revenue, before inter-segment eliminations	$	19,158		$	4,414		$	7,685		58	%
Operating costs, before inter-segment eliminations	$	15,357		$	2,989		5,410			83	%



Average number of drilling rigs in use	11.0			6.0			4.6			116	%
Total drilling rigs available for use at the end of the period	21			58			58			(64)	%
Average dayrate on daywork contracts	$	17,502		$	17,361		$	16,596		4	%

Mid-Stream:
Revenue, before inter-segment eliminations	$	92,022		$	17,284		$	34,132		79	%
Operating costs, before inter-segment eliminations	$	76,823		$	12,130		$	21,620		128	%


Gas gathered--Mcf/day	318,304			345,460			363,465			(11)	%
Gas processed--Mcf/day	128,161			145,263			149,483			(13)	%
Gas liquids sold--gallons/day	456,971			473,371			699,647			(27)	%
Number of natural gas gathering systems	17			18			18			(6)	%
Number of processing plants	11			11			11			—	%

Corporate and Other:

General and administrative expense, before inter-segment eliminations	$	4,246		$	1,582		$	5,399		(39)	%


Other income (expense):

Interest expense, net	$	(702)		$	(826)		$	(1,959)		(75)	%

Reorganization items, net	$	(971)		$	(1,155)		$	141,002		101	%
Gain (loss) on derivatives	$	(39,742)		$	3,939		$	(4,250)		NM
Loss on change in fair value of warrants	$	(9,054)		$	—		$	—		—	%

Income tax benefit	$	—		$	—		$	(4,750)		100	%
Average interest rate	6.5		%	5.9		%	2.7		%	76	%
Average long-term debt outstanding	$	18,393		$	146,267		$	160,039		(88)	%

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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 $24.6 million or 59% in the third quarter of 2021 as compared to the third quarter of 2020 primarily due to higher commodity prices, partially offset by lower production volumes. In the third quarter of 2021, as compared to the third quarter of 2020, oil production decreased 35%, natural gas production decreased 25%, and NGLs production decreased 23%. The decrease in volumes was due to normal well production declines and divestitures of producing properties which have not been offset by new drilling or acquisitions. Including derivatives settled, average oil prices increased 67% to $47.66 per barrel, average natural gas prices increased 125% to $2.88 per Mcf, and NGLs prices increased over 200% to $27.42 per barrel.

Oil and natural gas operating costs decreased 0.8 million or 3% between the comparative third quarters of 2021 and 2020 primarily due to the settlement of Predecessor Period liabilities subject to compromise under the Plan offset by increased production tax expenses due to increased revenues.

Contract Drilling

Drilling revenues increased $7.1 million or 58% in the third quarter of 2021 versus the third quarter of 2020. The increase was driven primarily by an increase in average number of rigs in use from 5.1 in the third quarter of 2020 to 11.0 in the third quarter of 2021.

Drilling operating costs increased $7.0 million or 83% between the comparative third quarters of 2021 and 2020. The change was primarily due to an increase in the average number of operating rigs and the associated start up costs bringing stacked rigs back into service.

Mid-Stream

Our mid-stream revenues increased $40.6 million or 79% in the third quarter of 2021 as compared to the third quarter of 2020 primarily due to higher gas, NGL, and condensate prices, partially offset by lower volumes. Gas processed volumes per day decreased 13% 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 11% between the comparative quarters due to declining volumes and fewer new well connections.

Operating costs increased 43.1 million or 128% in the third quarter of 2021 compared to the third quarter of 2020 primarily due to higher gas, NGL, and condensate prices, partially offset by lower purchase volumes.

General and Administrative

Corporate general and administrative expenses decreased $2.7 million or 39% in the third quarter of 2021 as compared to the third quarter of 2020 primarily due to reductions in payroll and benefits as well as the absence of separation benefits recognized in the third quarter of 2020.

Other Income (Expense)

Interest expense decreased $2.1 million between the comparative third quarters of 2021 and 2020 primarily due to an 88% decrease in average long-term debt outstanding, partially offset by a higher average interest rate. Our average interest rate increased from 3.7% in the third quarter of 2020 to 6.5% in the third quarter of 2021 and our average debt outstanding decreased $137.2 million in the third quarter of 2021 compared to the third quarter of 2020 primarily due to payments made under the Exit credit agreement, partially offset by borrowings under the Superior credit agreement.

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 $39.4 million primarily due to increases 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 $9.1 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 third quarter of 2021 compared to $4.8 million in the third quarter of 2020 due to the company's full valuation allowance against our net deferred tax asset. We paid no income taxes in the third quarter of 2021.

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Results of Operations

Nine Months Ended September 30, 2021 versus Nine Months Ended September 30, 2020

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


	Successor			Successor			Predecessor			Percent Change (1)
	Nine Months Ended September 30, 2021			One Month Ended September 30, 2020			Eight Months Ended August 31st, 2020
	(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations	$	451,850		$	35,342		$	291,493		38	%
Total revenue, after inter-segment eliminations	$	418,202		$	32,846		$	276,957		35	%
Net loss	$	(13,511)		$	(6,736)		$	(890,624)		99	%
Net income (loss) attributable to non-controlling interest	$	(4,875)		$	2,232		$	40,388		(111)	%
Net loss attributable to Unit Corporation	$	(8,636)		$	(8,968)		$	(931,012)		99	%

Oil and Natural Gas:
Revenue, before inter-segment eliminations	$	181,003		$	13,644		$	103,443		55	%
Operating costs, before inter-segment eliminations	$	58,365		$	6,892		$	119,664		(54)	%


Average oil price (Bbl)	$	47.77		$	28.11		$	32.02		51	%
Average oil price excluding derivatives (Bbl)	$	63.15		$	36.94		$	35.18		79	%
Average NGLs price (Bbl)	$	21.10		$	7.47		$	4.83		NM
Average NGLs price excluding derivatives (Bbls)	$	21.10		$	7.47		$	4.83		NM
Average natural gas price (Mcf)	$	2.87		$	1.72		$	1.14		139	%
Average natural gas price excluding derivatives (Mcf)	$	3.12		$	1.70		$	1.11		167	%
Oil production (MBbls)	1,130			167			1,560			(35)	%
NGLs production (MBbls)	1,952			273			2,399			(27)	%
Natural gas production (MMcf)	21,750			2,849			26,561			(26)	%


Contract Drilling:
Revenue, before inter-segment eliminations	$	52,893		$	4,414		$	73,519		(32)	%
Operating costs, before inter-segment eliminations	$	41,308		$	2,989		$	51,811		(25)	%




Average number of drilling rigs in use	10.1			6.0			11.5			(7)	%
Total drilling rigs available for use at the end of the period	21			58			58			(64)	%
Average dayrate on daywork contracts	$	17,944		$	17,361		$	18,911		(5)	%

Mid-Stream:
Revenue, before inter-segment eliminations	$	217,954		$	17,284		$	114,531		65	%
Operating costs, before inter-segment eliminations	$	181,109		$	12,130		$	80,607		95	%


Gas gathered--Mcf/day	300,484			345,460			388,506			(22)	%
Gas processed--Mcf/day	124,263			145,263			158,031			(21)	%
Gas liquids sold--gallons/day	431,474			473,371			612,301			(28)	%
Number of natural gas gathering systems	17			18			18			(6)	%
Number of processing plants	11			11			11			—	%

Corporate and Other:

General and administrative expense, before inter-segment eliminations	$	15,406		$	1,582		$	42,766		(65)	%


Other income (expense):

Interest expense, net	$	(3,895)		$	(826)		$	(22,882)		(84)	%
Write-off of debt issuance costs	$	—		$	—		$	(2,426)		(100)	%
Reorganization items, net	$	(3,959)		$	(1,155)		$	133,975		(103)	%
Gain (loss) on derivatives	$	(104,973)		$	3,939		$	(10,704)		NM

Loss on change in fair value of warrants	$	(12,628)		$	—		$	—		—	%
Income tax benefit	$	—		$	—		$	(14,630)		100	%
Average interest rate	6.7		%	5.9		%	5.5		%	21	%
Average long-term debt outstanding	$	57,815		$	146,267		$	526,167		(88)	%

_________________________

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

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Oil and Natural Gas

Oil and natural gas revenues increased $63.9 million or 55% in the first nine months of 2021 as compared to the first nine months of 2020 primarily due to higher commodity prices partially offset by lower production volumes. The decrease in volumes was due to normal well production declines and divestitures of producing properties which have not been offset by new drilling or acquisitions.

Oil and natural gas operating costs decreased 68.2 million or 54% between the comparative first nine months of 2021 and 2020 primarily due to the settlement of Predecessor Period liabilities subject to compromise under the Plan offset by increased production tax expenses due to increased revenues.

Contract Drilling

Drilling revenues decreased $25.0 million or 32% in the first nine months of 2021 versus the first nine months of 2020. The decrease was due primarily to lower rig termination and standby fees of $0.1 million in 2021 compared to $16.7 million in 2020. Additionally, there was a 7% decrease in the average number of drilling rigs in use and a 5% decrease in the average dayrate. Average drilling rig utilization decreased from 10.9 drilling rigs in the first nine months of 2020 to 10.1 drilling rigs in the first nine months of 2021.

Drilling operating costs decreased 13.5 million or 25% between the comparative first nine months of 2021 and 2020. The decrease was due primarily to the reduced number of drilling rigs operating.

Mid-Stream

Our mid-stream revenues increased $86.1 million or 65% in the first nine months of 2021 as compared to the first nine months of 2020 primarily due to higher prices, partially offset by lower volumes. Gas processed volumes per day decreased 21% between the comparative periods primarily due to declining volumes and fewer new wells connected to our processing systems. Gas gathered volumes per day decreased 22% 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 88.4 million or 95% in the first nine months of 2021 compared to the first nine 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 $28.9 million or 65% in the first nine months of 2021 as compared to the first nine months of 2020 primarily due to reductions in payroll and benefits, the absence of separation benefits recognized in the third quarter of 2020 as well as lower legal and office spend.

Other Income (Expense)

Interest expense decreased $19.8 million between the comparative first nine 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 5.5% in the first nine months of 2020 to 6.7% in the first nine months of 2021 and our average debt outstanding decreased $426.8 million in the first nine months of 2021 compared to the first nine 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

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 first nine months 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.

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Loss on Derivatives

Loss on derivatives increased by $98.2 million primarily due to increases in forward prices used to estimate the fair value in mark-to-market accounting.

Loss on Change in Fair Value of Warrants

Loss on change in fair value of warrants increased by $12.6 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 first nine months of 2021 compared to $14.6 million in the first nine months of 2020 due to the company's full valuation allowance against our net deferred tax asset. We paid no income taxes in the first nine 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 nine 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 $0.3 million 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 $0.1 million 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 $0.2 million 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.

At September 30, 2021, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Oct'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$(0.22)

NGPL TEXOK

Oct'21

Natural gas - swap

50,000 MMBtu/day

$2.82

IF - NYMEX (HH)

Nov'21 - Dec'21

Natural gas - swap

45,000 MMBtu/day

$2.90

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - swap

5,000 MMBtu/day

$2.61

IF - NYMEX (HH)

Jan'23 - Dec'23

Natural gas - swap

22,000 MMBtu/day

$2.46

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - collar

35,000 MMBtu/day

$2.50 - $2.68

IF - NYMEX (HH)

Oct'21 - Dec'21

Crude oil - swap

3,373 Bbl/day

$45.14

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 September 30, 2021 would reduce our annual pre-tax cash flow by less than $0.1 million. For further information, see Note 9 – Long-Term Debt and Other Long-Term Liabilities.

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Item 4. Controls and Procedures

Our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (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 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 CFO concluded that our disclosure controls and procedures were not effective as of September 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.

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 as of September 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 have conducted process improvement sessions with third party experts to enhance and augment business processes and utilization of system capabilities for greater effectiveness, efficiency, and scalability.

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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 September 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, except as set forth below.

The new OSHA rule requiring COVID-19 vaccination of employees could have a material adverse impact on our business and results of operations.

On November 4, 2021, OSHA released its interim final rule regarding the Biden administration's vaccination mandate for employers with 100 or more employees. The rule was published in the Federal Register and became effective on November 5, 2021. As a company with more than 100 employees, the rule requires us, by January 4, 2022, to mandate COVID-19 vaccination of our workforce or require our unvaccinated employees to be tested weekly and wear a face covering while working. This could result in higher-than-normal employee turnover and difficulty satisfying future workforce needs. In that case, it could have an adverse effect on future revenues and costs, and, correspondingly, on future profit margins, which could be material. For these reasons, the new rule could have a material adverse effect on our business and results of operations.

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

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. In October 2021, the Board authorized an increase from $25.0 million of authorized repurchases to $50.0 million. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. 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.

The table below represents all share repurchases for the three months ended September 30, 2021:


Period	Total number of shares purchased	Average price paid per share		Total number of shares purchased as part of publicly announced program	Approximate dollar value of shares that may yet be purchased under the program (1)
					(in thousands)
July 1, 2021 through July 31, 2021	—	$	—	—	$	25,000
August 1, 2021 through August 31, 2021	—	$	—	—	$	25,000
September 1, 2021 through September 30, 2021	428,037	$	25.31	350,037	$	15,653

1. Calculated as of September 30, 2021 without consideration to the subsequent increase in authorized repurchases described above.

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As of September 30, 2021, the company has repurchased a total of 350,037 shares at an average share price of $26.70 for an aggregate purchase price of $9.3 million under the repurchase program.

During the three months ended September 30, 2021, the company also repurchased 78,000 shares in a privately negotiation transaction at a share price of $19.07 outside of the repurchase program.

Subsequent to September 30, 2021, the company repurchased an additional 711,926 shares under the repurchase program at an average share price of $34.80 for an aggregate purchase price of $24.8 million bringing the aggregate shares repurchased under all methods since the Effective Date to 1,739,963 shares.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

Exhibits:


10.1			Third Amendment to Amended and Restated Credit Agreement effective October 20, 2021 .

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

10.3			Form of Stock Option Grant Notice and Award Agreement .

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

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

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

101.INS			XBRL Instance Document.

101.SCH			XBRL Taxonomy Extension Schema Document.

101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF			XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB			XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document.

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

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

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Part I. Financial Information Item 1. Financial Statements Note 1 Organization and Business Note 2 Summary Of Significant Accounting Policies Note 3 Impairments Note 4 Revenue From Contracts with Customers Note 5 Divestitures Note 6 Capital Stock Note 7 Earnings (loss) Per Share Note 8 Accrued Liabilities Note 9 Long-term Debt and Other Long-term Liabilities Note 10 Asset Retirement Obligations Note 11 Stock-based Compensation Note 12 Derivatives Note 13 Fair Value Measurements Note 14 Leases Note 15 Commitments and Contingencies Note 16 Variable Interest Entity Arrangements Note 17 Income Taxes Note 18 Industry Segment Information Note 19 Supplemental Condensed Consolidating Financial Information Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

Exhibits

10.1 Third Amendment to Amended and Restated Credit Agreement effective October 20, 2021. 10.2 Form of Restricted Stock Unit (RSU) Grant Notice and Award Agreement. 10.3 Form of Stock Option Grant Notice and Award Agreement. 31.1 Certification of Chief Executive Officer under Rule 13a 14(a) of the Exchange Act. 31.2 Certification of Chief Financial Officer under Rule 13a 14(a) of the Exchange Act. 32 Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a 14(a) of the Exchange Act and 18 U.S.C. Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.

UNTC 10-Q Quarter ended Sept. 30, 2021

Exhibits