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~~June 30, ~~2021~~2022

☐ 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~~August 11, 2022, 9,779,903 shares of the registrant's common stock were outstanding.

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TABLE OF CONTENTS

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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 to utilize the benefits of net operating losses and ~~the market's receptiveness, to execute a strategic divestiture process;~~

•~~our ability to retain or recruit key personnel throughout a strategic divestiture process;~~other deferred tax assets against potential future taxable income;

•the number of gathering systems and processing plants weour mid-stream investment may plan to construct or acquire;

•volumes and prices for the natural gas ~~we gather~~our mid-stream investment gathers and ~~process;~~processes;

•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 mid-stream investment's 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;~~ and

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

•Table of Contents~~our ability to carry out our post reorganization plans.~~

These statements are based on our assumptions and analyses ~~made by us based on~~considering 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~~risks and uncertainties are:

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

•general economic, market, or business conditions;

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

•demand for our land drilling services;

~~Table of Contents~~

•changes in laws and regulations;

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

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

•risks associated with future weather conditions;

•decreases or increases in commodity prices;

•the ~~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.”

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


		September 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
		(In thousands except share amounts)					(In thousands)
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	49,566	$	12,145	Cash and cash equivalents	$	115,628	$	64,140
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

Accounts receivable, net of allowance for credit losses of $2,355 and $2,511 as of June 30, 2022 and December 31, 2021, respectively						Accounts receivable, net of allowance for credit losses of $2,355 and $2,511 as of June 30, 2022 and December 31, 2021, respectively	69,268		87,248
Prepaid expenses and other	Prepaid expenses and other	6,120		11,212		Prepaid expenses and other	2,467		5,542
Total current assets	Total current assets	128,113		82,922		Total current assets	187,363		156,930
Property and equipment:	Property and equipment:					Property and equipment:
Oil and natural gas properties, on the full cost method:	Oil and natural gas properties, on the full cost method:					Oil and natural gas properties, on the full cost method:
Proved properties	Proved properties	225,786		238,581		Proved properties	224,462		225,014
Unproved properties not being amortized	Unproved properties not being amortized	247		1,591		Unproved properties not being amortized	2,194		422
Drilling equipment	Drilling equipment	64,278		63,687		Drilling equipment	70,062		66,058
Gas gathering and processing equipment	Gas gathering and processing equipment	259,642		251,404		Gas gathering and processing equipment	—		274,748
Land and building		—		32,635

Transportation equipment	Transportation equipment	3,750		3,130		Transportation equipment	2,024		4,550
Other	Other	8,892		9,961		Other	8,645		8,631
		562,595		600,989			307,387		579,423
Less accumulated depreciation, depletion, amortization, and impairment	Less accumulated depreciation, depletion, amortization, and impairment	103,794		54,189		Less accumulated depreciation, depletion, amortization, and impairment	88,133		128,880
Net property and equipment	Net property and equipment	458,801		546,800		Net property and equipment	219,254		450,543

Equity method investment (Note 15)						Equity method investment (Note 15)	1,658		—
Right of use asset (Note 14)	Right of use asset (Note 14)	13,800		5,592		Right of use asset (Note 14)	7,362		12,445
Other assets	Other assets	16,086		14,389		Other assets	6,755		9,559
Total assets (1)	Total assets (1)	$	616,800	$	649,703	Total assets (1)	$	422,392	$	629,477

1.Unit Corporation no longer consolidates the balance sheet of Superior Pipeline Company, L.L.C. (Superior) as of June 30, 2022, as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment. Unit Corporation's consolidated total assets as of December 31, 2021 included current and long-term assets of Superior of $61.1 million and $229.5 million, respectively, which can only be used to settle obligations of Superior. Unit Corporation's consolidated cash and cash equivalents of $64.1 million as of December 31, 2021 included $17.2 million held by Superior.

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) 0 0
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

~~_______________________~~


	June 30, 2022		December 31, 2021
	(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	31,718	$	58,625
Accrued liabilities (Note 8)	20,422		22,450
Current operating lease liability (Note 14)	1,571		3,791

Current derivative liabilities (Note 12)	48,844		40,876
Warrant liability (Note 12)	—		19,822
Current portion of other long-term liabilities (Note 9)	5,009		5,574
Total current liabilities	107,564		151,138
Long-term debt (Note 9)	—		19,200
Non-current derivative liabilities (Note 12)	17,231		17,855
Operating lease liability (Note 14)	5,853		8,677
Other long-term liabilities (Note 9)	31,376		32,939
Commitments and contingencies (Note 16)	0		0
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; 12,028,561 shares issued and 9,831,169 outstanding at June 30, 2022, and 12,000,000 shares issued and 10,050,037 outstanding at December 31, 2021	120		120
Treasury stock (Note 5)	(65,241)		(51,965)
Capital in excess of par value	251,202		198,171
Retained earnings	74,287		41,071
Total shareholders’ equity attributable to Unit Corporation	260,368		187,397
Non-controlling interests in consolidated subsidiaries	—		212,271
Total shareholders' equity	260,368		399,668
Total liabilities and shareholders’ equity (1)	$	422,392	$	629,477

~~(1)~~1.Unit ~~Corporation's consolidated total assets~~Corporation no longer consolidates the balance sheet of Superior as of ~~September~~June 30, ~~2021 include total current~~2022, as discussed in Note 2 - Summary Of Significant Accounting Policies 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.Note 15 - Superior Investment. Unit Corporation's consolidated total liabilities as of December 31, ~~2020 include total~~2021 included current and long-term liabilities of ~~the VIE~~Superior of ~~$28.4~~$42.3 million and ~~$2.6~~$21.2 million, ~~respectively, for which the creditors~~respectively. All of ~~the VIE have no recourse to~~ Unit ~~Corporation. See Note 16 – Variable Interest Entity Arrangements.~~Corporation's consolidated long-term debt of $19.2 million as of December 31, 2021 was held by Superior.

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)


	Three Months Ended June 30,				Six Months Ended June 30, 2022
	2022		2021		2022		2021
	(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	100,912	$	41,970	$	177,722	$	96,994
Contract drilling	33,642		18,061		62,524		33,735
Gas gathering and processing	—		74,026		82,673		124,225
Total revenues	134,554		134,057		322,919		254,954
Expenses:
Operating costs:
Oil and natural gas	27,619		15,487		51,094		34,636
Contract drilling	25,763		14,080		52,000		25,951
Gas gathering and processing	—		45,056		62,388		84,719
Total operating costs	53,382		74,623		165,482		145,306
Depreciation, depletion, and amortization	5,661		16,364		16,931		33,875


General and administrative	7,421		5,751		13,947		12,920
Gain on disposition of assets (Note 4)	(2,066)		(1,710)		(4,241)		(2,182)
Total operating expenses	64,398		95,028		192,119		189,919
Income from operations	70,156		39,029		130,800		65,035
Other income (expense):
Interest, net	(97)		(487)		(371)		(3,193)
Gain (loss) on derivatives (Note 12)	2,609		(42,400)		(61,467)		(65,231)
Gain (loss) on change in fair value of warrants (Note 12)	7,289		(3,574)		(29,323)		(3,574)
Loss on deconsolidation of Superior (Note 15)	—		—		(13,141)		—
Reorganization items, net	(39)		(1,852)		(42)		(2,988)
Other, net	175		(831)		932		(755)
Total other income (expense)	9,937		(49,144)		(103,412)		(75,741)
Income (loss) before income taxes	80,093		(10,115)		27,388		(10,706)
Income tax expense (benefit):
Current	—		—		—		—
Deferred	—		—		—		—
Total income taxes	—		—		—		—
Net income (loss)	80,093		(10,115)		27,388		(10,706)
Net income (loss) attributable to non-controlling interest (Note 15)	—		2,879		(5,828)		4,225
Net income (loss) attributable to Unit Corporation	$	80,093	$	(12,994)	$	33,216	$	(14,931)
Net income (loss) attributable to Unit Corporation per common share (Note 7):
Basic	$	7.99	$	(1.09)	$	3.31	$	(1.25)
Diluted	$	7.82	$	(1.09)	$	3.25	$	(1.25)

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.


	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)
Balances as of December 31, 2021	$	120	$	(51,965)	$	198,171	$	41,071	$	212,271	$	399,668
Net loss	—		—		—		(46,877)		(5,828)		(52,705)
Distributions to non-controlling interests	—		—		—		—		(9,479)		(9,479)
Deconsolidation of Superior	—		—		—		—		(196,964)		(196,964)
Activity in stock-based compensation plans	—		—		1,038		—		—		1,038
Balances as of March 31, 2022	$	120	$	(51,965)	$	199,209	$	(5,806)	$	—	$	141,558
Net income	—		—		—		80,093		—		80,093
Activity in stock-based compensation plans	—		—		2,848		—		—		2,848
Repurchases of common stock	—		(13,276)		—		—		—		(13,276)
Warrant liability reclassification	—		—		49,145		—		—		49,145
Balances as of June 30, 2022	$	120	$	(65,241)	$	251,202	$	74,287	$	—	$	260,368


	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)
Balances as of December 31, 2020	$	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 as of March 31, 2021	$	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)
Repurchases of common stock	—		(9,048)		—		—		—		(9,048)
Balances as of June 30, 2021	$	120	$	(9,048)	$	197,561	$	(33,071)	$	238,283	$	393,845

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF ~~CHANGES IN SHAREHOLDERS’ EQUITY~~CASH FLOWS (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


	Six Months Ended June 30, 2022
	2022		2021
	(In thousands)
OPERATING ACTIVITIES:
Net income (loss)	$	27,388	$	(10,706)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	16,931		33,875



Loss on derivatives (Note 12)	61,467		65,231
Cash payments on derivatives settled (Note 12)	(54,123)		(9,707)
Loss on change in fair value of warrants (Note 12)	29,323		3,574
Loss on deconsolidation of Superior (Note 15)	13,141		—
Gain on disposition of assets (Note 4)	(4,241)		(2,182)

Stock-based compensation plans (Note 6)	3,886		350
Change in credit loss reserve	(156)		482
ARO liability accretion (Note 10)	974		931
Contract assets and liabilities, net (Note 3)	83		1,584
Noncash reorganization items	(77)		433
Other, net	(673)		(1,009)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(23,090)		(6,336)

Prepaid expenses and other	2,288		2,536
Accounts payable	8,119		(2,279)
Accrued liabilities	7,079		(3,852)
Income taxes	(178)		1,116
Contract advances	(16)		(76)
Net change in operating assets and liabilities	(5,798)		(8,891)
Net cash provided by operating activities	88,125		73,965
INVESTING ACTIVITIES:
Capital expenditures	(16,474)		(7,673)

Deconsolidation of Superior cash and cash equivalents (Note 15)	(10,119)		—
Proceeds from disposition of property and equipment (Note 4)	12,711		15,278


Net cash provided by (used in) investing activities	(13,882)		7,605
FINANCING ACTIVITIES:
Borrowings under line of credit (Note 9)	—		3,900
Payments under line of credit (Note 9)	—		(67,900)



Net payments on finance leases (Note 14)	—		(3,216)






Distributions to non-controlling interests (Note 15)	(9,479)		(12,344)
Repurchases of common stock (Note 5)	(13,276)		(9,048)
Bank overdrafts	—		1,313
Net cash used in financing activities	(22,755)		(87,295)
Net increase (decrease) in cash and cash equivalents	51,488		(5,725)
Cash and cash equivalents, beginning of period	64,140		12,714
Cash and cash equivalents, end of period	$	115,628	$	6,989

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

~~Table of Contents~~

~~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			Six Months Ended June 30, 2022
		Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020			2022		2021
		(In thousands)							(In thousands)
Supplemental disclosure of cash flow information:	Supplemental disclosure of cash flow information:							Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Cash paid (received) for:								Cash paid (received) for:
Interest paid	Interest paid	$	4,307	$	251	$	6,417	Interest paid	$	456	$	3,764
Income taxes	Income taxes	(1,128)		—		—		Income taxes	178		(1,116)
Reorganization items	Reorganization items	4,026		131		4,822		Reorganization items	35		2,554

Changes in accounts payable and accrued liabilities related to purchases of property and equipment	Changes in accounts payable and accrued liabilities related to purchases of property and equipment	(3,356)		(128)		8,561		Changes in accounts payable and accrued liabilities related to purchases of property and equipment	(1,840)		(3,318)
Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations	Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations	(1,674)		(215)		29,189		Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations	(1,427)		1,115
Non-cash trade of property and equipment	Non-cash trade of property and equipment	—		—		1,403		Non-cash trade of property and equipment	30		—

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

109

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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~~refer 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~~primarily located in Oklahoma and Texas, and to a lesser extent, in Arkansas, Kansas, Louisiana, ~~Montana,~~and North ~~Dakota, Utah, and Wyoming.~~Dakota.

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~~primarily located in Oklahoma, Texas, New Mexico, Wyoming, and North Dakota.

Mid-Stream. Carried out by ~~our subsidiary,~~ Superior of which we ~~buy, sell, gather, transport, process,~~own 50%, buys, sells, gathers, transports, processes, and ~~treat~~treats natural gas for ~~our own account~~UPC and for third parties. ~~Mid-stream~~Mid-Stream operations are ~~performed~~primarily located 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~~2021 included in the company’s Annual Report on Form 10-K as filed with the SEC on March 31, ~~2021.~~2022.

In the opinion of management, the unaudited condensed consolidated financial statements are fairly stated and 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.

The unaudited condensed consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. We consolidated the financial position, operating results, and cash flows of Superior prior to March 1, 2022, on which date the Master Services and Operating Agreement (MSA) was amended and restated, with the result that we no longer consolidate Superior's financial position, operating results, and cash flows during periods subsequent to March 1, 2022. Accordingly, the unaudited condensed consolidated financial statements and notes reflect Superior activity on a consolidated basis for the two months prior to March 1, 2022. See Note 15 – Superior Investment for more information on the Superior investment and consolidation conclusions. All intercompany transactions and accounts between consolidated entities have been eliminated, including activity between Unit and Superior during the two months prior to March 1, 2022. Intercompany transactions and accounts between Unit and Superior subsequent to March 1, 2022 are not eliminated.

Table of Contents

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.

~~Table of Contents~~

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 and ASU 2021-01 which ~~provides~~provide and clarify optional expedients and exceptions for applying ~~GAAP~~generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The ~~ASU is intended to help stakeholders during the global market-wide reference rate transition period. The~~ amendments within ~~this ASU~~these ASUs will be in effect for a limited time beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. ~~The amendments will~~In April 2022, the FASB proposed to defer the effective date to December 31, 2024, but a final ruling has not been issued. We have ~~a material impact on our unaudited condensed consolidated financial statements.~~

~~Adopted Standards~~

~~Income Taxes (Topic 740)—Simplifying~~not yet elected to use the ~~Accounting for Income Taxes.~~ ~~The FASB issued~~optional guidance and continue to evaluate the options provided by 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~~2020-04 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.ASU 2021-01.

~~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.

~~Table of Contents~~

~~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 43 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Our revenue streams are reported under 3 segments: oil and natural gas, contract drilling, and mid-stream which is consistent with how we report our segment revenue ~~(as reflected~~ in Note 1819 – Industry Segment ~~Information).~~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~~Revenues from the mid-stream segment ~~is derived~~are generated from the fees earned for gas gathering ~~transporting,~~ and processing ~~natural gas and NGLs and~~services provided to a customer or by selling ~~those commodities.~~of hydrocarbons to other mid-stream companies.

Oil and Natural Gas Revenue

Typical types of revenue contracts entered into by our oil and gas segment are Oil Sales Contracts, North American Energy Standards Board (NAESB) Contracts, Gas Gathering and Processing Agreements, and revenues earned as the non-operated party with the operator serving as an agent on our behalf under joint operating agreements. Consideration received is variable and settled monthly while contract terms can range from a single month or evergreen to terms of a decade or more. Revenues from oil and natural gas sales are recognized when the customer obtains control of the sold product which typically occurs at the point of delivery to the customer.

Certain ~~costs—~~costs, as either a deduction from revenue or as an ~~expense—~~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 are 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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Table of Contents

Contract Drilling ~~Revenues~~Revenue

~~Mobilization~~Contract drilling revenues and ~~de-mobilization charges from our drilling contracts~~expenses are primarily recognized as services are performed and collection is reasonably assured. Payments for mobilization and demobilization activities do not relate to a distinct good or ~~service. These~~service within the contract and are deferred for ratable recognition when material. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred and any reimbursements received for out-of-pocket expenses are recorded as both 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 9 contract drilling contracts with remaining terms ranging from ~~two~~ ~~to fifteen months.~~direct costs.

Most of our drilling contracts have ~~an original~~a term of one year or less ~~than one year. The~~and the remaining performance obligations under the contracts ~~with~~without a ~~longer duration~~fixed term are not material.

Mid-Stream ~~Contracts Revenues~~Revenue

~~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.

Superior recognizes sales revenue at the point in time when control transfers to the purchaser, typically at a specified delivery point, based on the contractually agreed upon fixed or index-based price received. Contracts for gas gathering and processing services may include terms for demand fees or shortfall fees. Demand fees ~~represent an arrangement~~or shortfall fees exist in arrangements where a customer agrees to pay a fixed fee for a contractually agreed upon pipeline capacity or shortfall fees for any minimum volumes not utilized, which ~~results in~~create performance obligations for each individual period of reservation. ~~Once~~Revenue for these fees is recognized once the services have been completed, or the customer no longer has access to the contracted capacity, ~~revenue is recognized.~~or the likelihood of the customer exercising all or a portion of their remaining rights becomes remote.

Contract Assets and Liabilities

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:~~presented:

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



	Classification on the unaudited condensed consolidated balance sheets	June 30, 2022		December 31, 2021		Change
		(In thousands)
Assets
Current contract assets	Prepaid expenses and other	$	—	$	174	$	(174)
Non-current contract assets	Other assets	—		—		—
Total contract assets		$	—	$	174	$	(174)

Liabilities
Current contract liabilities	Current portion of other long-term liabilities	$	560	$	1,588	$	(1,028)
Non-current contract liabilities	Other long-term liabilities	188		200		(12)
Total contract liabilities		748		1,788		(1,040)
Contract assets (liabilities), net		$	(748)	$	(1,614)	$	866

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NOTE 54 – 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 iswas 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~~reserves, and on January 20, 2022, the company ~~expects~~announced that it had retained a financial advisor and launched the process. On June 10, 2022, the company announced that it had ended its engagement with the financial advisor and terminated the process. During the process, the Company entered into an agreement to ~~enhance various severance~~sell its Texas Gulf Coast oil and ~~certain other related benefits in response to the Divestiture Program.~~gas properties.

On ~~June 25, 2021,~~July 1, 2022, the company ~~entered into a purchase and~~closed on the sale ~~agreement in which we agreed to sell substantially all~~ of ~~our~~certain wells and related leases near the ~~leases related thereto located near Oklahoma City, Oklahoma~~Texas Gulf Coast for ~~$19.5~~cash proceeds of $43.7 million, subject to customary ~~closing and~~ post-closing ~~adjustments. The divestiture closed~~adjustments based on ~~August 16, 2021, with~~ an effective date of ~~May~~April 1, ~~2021. The~~2022. These proceeds will reduce the net book value of our full cost pool with no gain or loss recognized as the sale ~~of these assets~~ did not result in a significant alteration of the full cost pool.

On March 8, 2022, the company closed on the sale of certain non-core wells and ~~therefore~~related leases located near the Oklahoma Panhandle for cash proceeds of $4.1 million net of customary closing and post-closing adjustments based on an effective date of December 1, 2021. These proceeds reduced the net book value of our full cost pool with no gain or loss ~~was recognized.~~recognized as the sale did not result in a significant alteration of the full cost pool.

On ~~March 30,~~May 6, 2021, the company ~~entered into a purchase and~~closed on the sale ~~agreement in which we agreed to sell~~of substantially all of our wells and the leases related thereto located in Reno and Stafford Counties, Kansas for proceeds of $7.1 million, ~~subject to customary closing and~~excluding 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.~~recognized as the sale did not result in a significant alteration of the full cost pool.

Net proceeds for the sale of other non-core oil and natural gas assets totaled $1.9 million and $2.7 million during the three months ended June 30, 2022 and 2021, respectively, and $2.3 million and $4.4 million during the six months ended June 30, 2022 and 2021, respectively. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sales did not result in a significant alteration of the full cost pool.

Contract Drilling

~~We sold~~Proceeds for the sale of non-core contract drilling assets ~~for proceeds of $4.3~~totaled $4.2 million and ~~$8.2~~$1.9 million ~~net of related expenses,~~ during the three ~~and nine~~ months ended ~~September~~June 30, 2022 and 2021, ~~compared to $2.0~~respectively, and $6.4 million and ~~$4.8~~$3.9 million during the ~~two and eight~~six months ended ~~August 31, 2020,~~June 30, 2022 and ~~$0.6 million during the one month ended September 30, 2020.~~2021, respectively. These proceeds resulted in net gains of ~~$3.1~~$2.0 million and ~~$5.2~~$1.6 million during the three ~~and nine~~ months ended ~~September~~June 30, 2022 and 2021, ~~compared to $1.3~~respectively, and $4.2 million and ~~$1.4~~$2.1 million during the ~~two and eight~~six months ended ~~August 31, 2020,~~June 30, 2022 and ~~$0.2 million during~~2021, respectively. The net gains are presented within gain on disposition of assets in the ~~one month ended September 30, 2020.~~

~~Corporate and Other~~

~~On September 17, 2021, we closed the sale~~unaudited condensed consolidated statements 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.operations.

NOTE 65 – CAPITAL STOCK

OnStock Repurchases

In June ~~16,~~ 2021, ~~the company~~we repurchased an aggregate of 600,000 shares of ~~its~~our common stock from the Lenders (as defined in Note 9 - Long-Term Debt ~~and~~And Other Long-Term Liabilities) which received these shares as an exit fee during ~~the company’s~~our reorganization. The Lenders were paid $15.00 per share for their respective shares, for an aggregate cash purchase price of $9.0 million. ~~The cash purchase price and direct acquisition costs are reflected as treasury stock on the 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. InThe Board subsequently authorized increases to the authorized repurchases up to $50.0 million in October 2021 ~~the Board authorized an increase from $25.0~~and then up to $100.0 million ~~of authorized repurchases to $50.0 million.~~in June 2022. 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~~June 30, ~~2021, the company has~~2022, we had repurchased a total of ~~350,037~~1,519,392 shares under the repurchase program at an average share price of ~~$26.70~~$36.00 for an aggregate purchase price of ~~$9.3 million~~$54.7 million. Subsequent to June 30, 2022, we have repurchased an additional 75,000 shares under the repurchase ~~program.~~program for an aggregate purchase price of $3.8 million.

During the ~~three months~~year ended ~~September 30,~~December 31, 2021, ~~the company~~we also repurchased 78,000 shares in a privately negotiated transaction at a share price of $19.07 which were not part of the repurchase program.

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~~Subsequent~~

The cumulative number of shares repurchased as of June 30, 2022 totaled 2,197,392. The cash purchase price and any direct acquisition costs are reflected as treasury stock on the unaudited condensed consolidated balance sheets as of June 30, 2022.

Warrants

Each holder of Unit common stock outstanding (Old Common Stock) before the September 3, 2020 emergence from bankruptcy (Emergence Date) that did not opt out of the release under the Chapter 11 plan of reorganization filed with the bankruptcy court on June 9, 2020 is entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant is exercisable for one share of common stock, subject to adjustment as provided in the Warrant Agreement. 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, dissolution or winding up of the company. As of June 30, ~~2021,~~2022, the company ~~repurchased~~had issued 1,822,203 warrants.

Among other provisions, the Warrant Agreement outlines potential adjustments to the warrants if certain events occur, including (i) stock dividends payable in shares of common stock or stock splits, (ii) reverse stock splits or similar combination events, (iii) Liquidity Events (as defined in the Warrant Agreement), and (iv) other events not explicitly contemplated which may have an ~~additional 711,926 shares under~~adverse impact to the ~~repurchase program at an average~~intent and purpose of the warrants as set forth in the Plan, provided, however, the warrants will not be adjusted for (a) any issuances of securities in connection with a merger, share ~~price~~exchange, asset acquisition, stock purchase, recapitalization, reorganization or other similar business combination, (b) the issuance of ~~$34.80 for an aggregate purchase price of $24.8 million bringing the aggregate shares repurchased under all methods since~~any securities by Unit on or after the Effective Date (as defined in the Plan) pursuant to ~~1,739,963 shares.~~the Plan or upon the issuance of shares of common stock upon the exercise of such securities, (c) the issuance of any shares of common stock pursuant to the exercise of the warrants, (d) the issuance of shares of common stock pursuant to any management stock option incentive or similar plan, (e) a dividend or distribution to holders of common stock of cash, property, or securities (other than common stock), and/or (f) any change in the par value of the common stock.

Pursuant to the terms of the Warrant Agreement, the company determined the initial exercise price of the warrants to be $63.74. On April 7, 2022, the company delivered notice of the initial exercise price to the Warrant Agent and the warrants became exercisable for shares of the company’s common stock. On or about April 25, 2022, the warrants began trading over-the-counter under the symbol "UNTCW".

See Note 12 - Derivatives for more information on how the warrants are treated in our unaudited condensed consolidated financial statements.

~~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 6 – 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 will be administered by the Board or a committee thereof and 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 (RSUs), 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 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.

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The table below summarizes the stock-based compensation expense activity recognized during the following periods:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In thousands)
Recognized stock compensation expense	$	2,847	$	216	$	3,885	$	216
Capitalized stock compensation cost for our oil and natural gas properties	—		—		—		—
Tax benefit on stock-based compensation	$	697	$	53	$	952	$	53

The tables below summarize the activity pertaining to nonvested RSUs during the three and six months ended June 30, 2022 and 2021:


	Three Months Ended June 30,
	2022			2021
	Number of Shares	Weighted Average Grant Date Fair Value		Number of Shares	Weighted Average Grant Date Fair Value
Nonvested RSUs, beginning of period	322,855	$	26.80	—	$	—
Granted	—	—		109,008	12.90
Vested	(28,037)	13.39		—	—
Forfeited	—	—		—	—
Nonvested RSUs, end of period	294,818	$	28.07	109,008	$	12.90


	Six Months Ended June 30,
	2022			2021
	Number of Shares	Weighted Average Grant Date Fair Value		Number of Shares	Weighted Average Grant Date Fair Value
Nonvested RSUs, beginning of period	315,529	$	26.71	—	$	—
Granted (1)	7,850	30.50		109,008	12.90
Vested	(28,561)	13.71		—	—
Forfeited	—	—		—	—
Nonvested RSUs, end of period (2)	294,818	$	28.07	109,008	$	12.90

1.RSUs granted in January 2022 had an aggregate grant date fair value of $0.2 million and vest equally each month for thirty months. RSUs granted in April 2021 had an aggregate grant date fair value of $1.4 million and vest 25% on each of the following dates: May 27, 2022, September 3, 2022, September 3, 2023, and September 3, 2024.

2.The aggregate compensation cost related to nonvested RSUs not yet recognized as of June 30, 2022 was $5.6 million with a weighted average remaining service period of 1.3 years.

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The tables below summarize the activity pertaining to outstanding stock options during the three and six months ended June 30, 2022 and 2021:


	Three Months Ended June 30,
	2022			2021
	Number of Shares	Weighted Average Exercise Price		Number of Shares	Weighted Average Exercise Price
Outstanding stock options, beginning of period	374,834	$	45.00	—	$	—
Granted	—	—		—	—
Exercised	—	—		—	—
Forfeited or expired	—	—		—	—
Outstanding stock options, end of period	374,834	$	45.00	—	$	—


	Six Months Ended June 30,
	2022			2021
	Number of Shares	Weighted Average Exercise Price		Number of Shares	Weighted Average Exercise Price
Outstanding stock options, beginning of period	361,418	$	45.00	—	$	—
Granted (1)	13,416	45.00		—	—
Exercised	—	—		—	—
Forfeited or expired	—	—		—	—
Outstanding stock options, end of period (2)	374,834	$	45.00	—	$	—

1.Stock options granted in January 2022 had an aggregate grant date fair value of $0.1 million and 100% vest on the first anniversary of the grant date.

2.Stock options outstanding as of June 30, 2022 had a weighted average remaining contractual term of 4.2 years and an aggregate intrinsic value of $2.1 million. None of the stock options outstanding as of June 30, 2022 were exercisable. The aggregate compensation cost related to outstanding options not yet recognized as of June 30, 2022 was $2.6 million with a weighted average remaining service period of 1.2 years.

NOTE 7 – EARNINGS (LOSS) PER SHARE

The tables below show the calculation of loss per share attributable to Unit Corporation using the treasury stock method for the periods indicated:


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
Three months ended June 30, 2022
Basic earnings attributable to Unit Corporation per common share	$	80,093	10,025	$	7.99
Effect of dilutive restricted stock units and stock options (1)	—		223	(0.17)
Diluted earnings attributable to Unit Corporation per common share	$	80,093	10,248	$	7.82
Three months ended June 30, 2021
Basic loss attributable to Unit Corporation per common share	$	(12,994)	11,901	$	(1.09)
Effect of dilutive restricted stock units (2)	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(12,994)	11,901	$	(1.09)

1.The diluted earnings per share calculation for the three months ended June 30, 2022 excludes the effects related to 1,822,203 average outstanding warrants with a $63.74 exercise price because their inclusion would be antidilutive.

2.The diluted loss per share calculation for the three months ended June 30, 2021 excludes the effect related to 77,863 average outstanding restricted stock units because their inclusion would be antidilutive.

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	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
Six months ended June 30, 2022
Basic earnings attributable to Unit Corporation per common share	$	33,216	10,037	$	3.31
Effect of dilutive restricted stock units and stock options (1)	—		189	(0.06)
Diluted earnings attributable to Unit Corporation per common share	$	33,216	10,226	$	3.25
Six months ended June 30, 2021
Basic loss attributable to Unit Corporation per common share	$	(14,931)	11,950	$	(1.25)
Effect of dilutive restricted stock units (2)	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(14,931)	11,950	$	(1.25)

1.The diluted earnings per share calculation for the six months ended June 30, 2022 excludes the effects related to 361,418 average outstanding stock options with a $45.00 exercise price and 1,822,203 average outstanding warrants with a $63.74 exercise price because their inclusion would be antidilutive.

2.The diluted loss per share calculation for the six months ended June 30, 2021 excludes the effect related to 39,147 average outstanding restricted stock units because their inclusion would be antidilutive.

NOTE 8 – ACCRUED LIABILITIES

~~Accrued~~The table below provides detail on our accrued liabilities ~~consisted of:~~as of the dates indicated:

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



	June 30, 2022		December 31, 2021
	(In thousands)
Employee costs	$	11,565	$	10,005
Lease operating expenses	3,735		3,451
Capital expenditures	1,658		3,962
Taxes	2,315		3,320
Interest payable	97		296

Other	1,052		1,416
Total accrued liabilities	$	20,422	$	22,450

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

Long-Term Debt

AsThe table below provides detail on our outstanding long-term debt as of the ~~date indicated, our long-term debt consisted of the following:~~dates indicated:

~~September~~June 30,
~~2021~~2022

December 31,
~~2020~~2021

(In thousands)

~~Current portion of long-term~~Long-term debt:

Exit credit agreement ~~with an average interest rate of 6.6% at December 31, 2020~~

—

~~600~~—

~~Long-term debt:~~

~~Exit~~Superior credit agreement ~~with an average interest rate of 6.6% at December 31, 2020~~(1)

—

~~98,400~~19,200

~~Superior credit agreement with an average interest rate of 2.1% at September 30, 2021~~

1.Unit Corporation no longer consolidates the balance sheet of Superior as of June 30, 2022, as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment.~~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).

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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 Facility, 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.

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 Facility borrowing base from $140.0 million to $80.0 million in addition to less restrictive terms as it relates to capital expenditures, required hedges, and the use of proceeds from the disposition of certain assets, while also amending certain financial covenants.

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

On July 1, 2022, the RBL Facility borrowing base was automatically reduced to $31.3 million as a result of closing the Texas Gulf Coast properties sale discussed in Note 4 - Divestitures.

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.

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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~~June 30, ~~2021,~~2022, 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~~As of June 30, ~~2021,~~2022, we had no long-term borrowings and ~~$3.2~~$2.4 million of letters of credit outstanding under the Exit credit agreement.

Superior Credit Agreement. On May 10, 2018, Superior ~~signed~~entered into 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~~bore 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~~required 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~~contained 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.~~covenants as of June 30, 2022.

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On April 29, 2022, Superior entered into an Amended and Restated Credit Agreement for a four-year, $135.0 million senior secured revolving credit facility with an option to increase the credit amount up to $200.0 million, subject to certain conditions (Amended Superior credit agreement). The amounts borrowed under the Amended Superior credit agreement ~~is used~~bear annual interest at a rate, at Superior’s option, equal to ~~fund capital expenditures~~(a) SOFR plus the applicable margin of 2.75% to 3.75% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, 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~~(iii) SOFR plus 0.10%). The obligations under the Amended Superior credit ~~agreement.~~

agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems. Unit is not a party to and does not guarantee ~~Superior's~~the Amended Superior credit agreement.

19The Amended 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 3.50 to 1.00. Additionally, the Amended Superior credit agreement contains a number of customary covenants that, among other things, restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, enter into sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, enter into hedging arrangements, and acquire or dispose of assets.

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Other Long-Term Liabilities

~~Other~~The table below provides detail on our other long-term liabilities ~~consisted~~as of the ~~following:~~dates indicated:

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



	June 30, 2022		December 31, 2021
	(In thousands)
Asset retirement obligation (ARO) liability	$	25,406	$	25,688
Workers’ compensation	7,483		7,925
Contract liability	748		1,788
Separation benefit plans	1,658		2,022
Gas balancing liability	1,090		1,090

	36,385		38,513
Less: current portion	5,009		5,574
Total other long-term liabilities	$	31,376	$	32,939

NOTE 10 – ASSET RETIREMENT OBLIGATIONS

We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All our AROs relate to the plugging costs associated with our oil and gas wells.

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


~~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~~

~~_______________________~~


	Six Months Ended June 30,
	2022		2021
	(In thousands)
ARO liability, beginning of period	$	25,688	$	23,356
Accretion of discount	974		931
Liability incurred	17		1
Liability settled	(86)		(302)
Liability sold	(2,671)		(721)
Revision of estimates (1)	1,484		(93)
ARO liability, end of period	25,406		23,172
Less: current portion	2,707		2,132
Total long-term ARO	$	22,699	$	21,040

1.Plugging liability estimates were revised in 2022 and 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.

NOTE 11 – WORKERS' COMPENSATION

We are liable for workers' compensation benefits for traumatic injuries through our self-insured program to provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers' compensation laws also compensate survivors of workers who suffer employment related deaths. Our liability for traumatic injury claims is the estimated present value of current workers' compensation benefits, based on our actuarial estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including claim development patterns, mortality, medical costs and interest rates.

The following table summarizes activity for our workers' compensation liability during the periods indicated:


	Six Months Ended June 30,
	2022		2021
	(In thousands)
Workers' compensation liability, beginning of period	$	7,925	$	10,164
Claims and valuation adjustments	(229)		1,748
Payments	(213)		(182)
Workers' compensation liability, end of period	7,483		11,730
Less: current portion	1,283		1,819
Long-term workers' compensation liability	$	6,200	$	9,911

Our workers' compensation liability above is presented on a gross basis and does not include our expected receivables on our insurance policy. Our receivables for traumatic injury claims under these policies as of June 30, 2022 and December 31, 2021 are $3.8 million and $4.0 million, respectively, and are included in other assets on our unaudited condensed consolidated balance sheets.

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NOTE 12 – DERIVATIVES

Commodity Derivatives

We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions as well as certain requirements stipulated in the Exit credit agreement. Our commodity derivative transactions consisted of the following types of hedges as of June 30, 2022:

•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 and have not designated any of our hedges for hedge accounting purposes. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of June 30, 2022.

The following non-designated commodity hedges were outstanding as of June 30, 2022:

~~ARO liability, December 31, 2019 (Predecessor)~~Term

Commodity

Contracted Volume

Weighted Average

Fixed Price for Swaps

Contracted Market

Jul'22 - Dec'22

Natural gas - swap

5,000 MMBtu/day

~~66,627~~

~~Accretion of discount~~2.61

~~1,545~~ IF - NYMEX (HH)

~~Liability incurred~~Jul'22 - Feb'23

~~465~~

~~Liability settled~~Natural gas - swap

~~(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~~18,765 MMBtu/day

$9.14

~~22,736~~ IF - NYMEX (HH)

Jan'23 - Dec'23

Natural gas - swap

22,000 MMBtu/day

$2.46

IF - NYMEX (HH)

Jul'22 - Dec'22

Natural gas - collar

35,000 MMBtu/day

$2.50 - $2.68

IF - NYMEX (HH)

Jul'22 - Dec'22

Crude oil - swap

2,300 Bbl/day

$42.25

WTI - NYMEX

Jul'22 - Dec'22

Crude oil - swap

596 Bbl/day

$103.98

WTI - NYMEX

Jan'23 - Feb'23

Crude oil - swap

1,339 Bbl/day

$95.40

WTI - NYMEX

Jan'23 - Dec'23

Crude oil - swap

1,300 Bbl/day

$43.60

WTI - NYMEX

~~_______________________~~

Warrants

1.
~~Plugging~~

Prior to the determination of the initial exercise price, we recognized the fair value of the warrants as a derivative liability ~~estimates were revised in 2020 for updates~~on our unaudited condensed consolidated balance sheets with changes in the ~~cost~~liability reported as gain (loss) on change in fair value of ~~services used~~warrants in our unaudited condensed consolidated statements of operations. On April 7, 2022, the company delivered notice of the initial $63.74 exercise price resulting in the warrants meeting the definition of an equity instrument. Accordingly, we recognized the change in the fair value of the warrant liability in our unaudited condensed consolidated statements of operations and reclassified the $49.1 million warrant liability to ~~plug wells over~~capital in excess of par value on the ~~preceding year. We had various upward~~unaudited condensed consolidated balance sheets as of April 7, 2022. The warrants will continue to be reported as capital in excess of par and ~~downward~~are no longer subject to future fair value adjustments.

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The following tables present the recognized derivative assets and liabilities on our unaudited condensed consolidated balance sheets:


		Balances as of June 30, 2022
	Balance Sheet Classification	Presented Gross		Effects of Netting		Presented Net
		(In thousands)
Assets:
Current Commodity Derivatives	Current derivative assets	$	16,481	$	(16,481)	$	—
Long-term Commodity Derivatives	Non-current derivative assets	—		—		—
Total derivative assets		$	16,481	$	(16,481)	$	—
Liabilities:
Current Commodity Derivatives	Current derivative liabilities	$	65,325	$	(16,481)	$	48,844
Long-term Commodity Derivatives	Non-current derivative liabilities	17,231		—		17,231
Total derivative liabilities		$	82,556	$	(16,481)	$	66,075


		Balances as of December 31, 2021
	Balance Sheet Classification	Presented Gross		Effects of Netting		Presented Net
		(In thousands)




Liabilities:
Current Commodity Derivatives	Current derivative liabilities	$	40,876	$	—	$	40,876
Long-term Commodity Derivatives	Non-current derivative liabilities	17,855		—		17,855
Warrant Liability	Warrant liability	19,822		—		19,822
Total derivative liabilities		$	78,553	$	—	$	78,553

The following table shows the activity related to derivative instruments in the unaudited condensed consolidated statements of operations for the periods indicated:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In thousands)
Gain (loss) on derivatives	$	2,609	$	(42,400)	$	(61,467)	$	(65,231)
Cash settlements paid on commodity derivatives	(32,884)		(6,403)		(54,123)		(9,707)
Gain (loss) on derivatives less cash settlements paid on commodity derivatives	$	35,493	$	(35,997)	$	(7,344)	$	(55,524)

Gain (loss) on change in fair value of warrants	$	7,289	$	(3,574)	$	(29,323)	$	(3,574)

~~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.

~~Table of Contents~~

~~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~~

~~Table of Contents~~

~~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.

The inputs available determine the valuation technique that we use to measure the fair value of the assets and liabilities presented in our unaudited condensed consolidated financial statements. Fair value ~~is defined as~~measurements are categorized into one of three different levels depending on the ~~amount that would be received from~~observability of the ~~sale of an asset or paid for transferring a liability~~inputs used 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.~~measurement. The levels are summarized as follows:

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•Level 1—~~unadjusted~~observable inputs such as quoted prices in active markets for identical assets and liabilities.

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

•Level 3—generally unobservable inputs which are developed based on the best information available and may include our own internal ~~data.~~data or estimates about how market participants would value such assets and liabilities.

~~The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments.~~Recurring Fair Value Measurements

~~Table of Contents~~

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)
measurements by level:

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)


	Balances as of June 30, 2022
	Level 1		Level 2		Level 3		Total
	(In thousands)
Financial liabilities:
Commodity derivative liabilities	$	—	$	66,075	$	—	$	66,075
	$	—	$	66,075	$	—	$	66,075

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.


	Balances as of December 31, 2021
	Level 1		Level 2		Level 3		Total
	(In thousands)
Financial liabilities:
Commodity derivative liabilities	$	—	$	58,731	$	—	$	58,731
Warrant liability	—		—		19,822		19,822
	$	—	$	58,731	$	19,822	$	78,553

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.

~~Table of Contents~~

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. The following methods and assumptions were used 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 liabilities.

~~Fair Value~~Commodity Derivatives. We measure the fair values of ~~Non-Financial Instruments~~our crude oil and natural gas swaps and collars using estimated discounted cash flow calculations based on the NYMEX futures index. We consider these Level 2 measurements within the fair value hierarchy as the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts.

We determined that the non-performance risk regarding our commodity derivative counterparties was immaterial based on our valuation at June 30, 2022.

Warrant Liability. We use the Black-Scholes option pricing model to measure the fair value of the warrants. Key inputs for the Black-Scholes model include the stock price, exercise price, expected term, risk-free rate, volatility, and dividend yield. We consider this a Level 3 measurement within the fair value hierarchy as estimated volatility is generally unobservable and requires management's estimation.

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The following table summarizes the activity of our recurring Level 3 fair value measurements during the periods presented:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In thousands)
Beginning of period	$	56,434	$	885	$	19,822	$	885
(Gain) loss on change in warrant liability	(7,289)		3,574		29,323		3,574
Reclassification of warrant liability to capital in excess of par value	(49,145)		—		(49,145)		—
End of period	$	—	$	4,459	$	—	$	4,459

Nonrecurring Fair Value Measurements

ARO.The initial measurement of ~~AROs~~ARO 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~~summary of ~~our AROs~~the company’s ARO activity is presented in Note 10 – Asset Retirement Obligations.

Stock-Based Compensation. We use the Black-Scholes option pricing model to estimate the fair value of stock option grants while the value of our restricted stock grants is based on the grant date closing stock price. Key assumptions for the Black-Scholes models include the stock price, exercise price, expected term, risk-free rate, volatility, and dividend yield. We consider this a Level 3 measurement within the fair value hierarchy as estimated volatility is generally unobservable and requires management's estimation.

See Note 15 - Superior Investment for discussion on the estimated fair value of our retained equity method investment in Superior as of March 1, 2022.

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NOTE 14 – LEASES

~~Lease Agreements.~~Operating Leases. We are a lessee through noncancellable lease ~~certain~~agreements for property and equipment consisting primarily of office space, land, vehicles, and equipment ~~including pipeline equipment~~used in both our operations 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.administrative functions.

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.

~~Table of Contents~~

The following table sets forth the ~~maturity~~maturities, weighted average remaining lease term, and weighted average discount rate of our operating lease liabilities as of ~~September~~June 30, ~~2021:~~2022:

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


	Amount
	(In thousands)
Ending June 30,
2022	$	2,017
2023	1,996
2024	2,024
2025	2,065
2026	437
2027 and beyond	—
Total future payments	8,539
Less: Interest	1,115
Present value of future minimum operating lease payments	7,424
Less: Current portion	1,571
Total long-term operating lease payments	$	5,853

Weighted average remaining lease term (years)	4.2
Weighted average discount rate (1)	6.65		%

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.

Finance ~~Leases~~Leases. ~~under ASC 842~~

InDuring 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%~~4.0% and the underlying assets were included in gas gathering and processing equipment. ~~In May 2021,~~ Superior purchased the leased assets for $3.0 ~~million.~~million in May 2021.

2625

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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


	Classification on the unaudited condensed consolidated balance sheets	June 30, 2022		December 31, 2021
		(In thousands)
Assets
Operating lease right of use assets	Right of use assets	$	7,362	$	12,445
Total right of use assets		$	7,362	$	12,445

Liabilities
Current liabilities:
Operating lease liabilities	Current operating lease liabilities	$	1,571	$	3,791
Non-current liabilities:
Operating lease liabilities	Operating lease liabilities	5,853		8,677
Total lease liabilities		$	7,424	$	12,468

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

~~_______________________~~


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In thousands)
Components of total lease cost:
Amortization of finance leased assets	$	—	$	181	$	—	$	1,248
Interest on finance lease liabilities	—		4		—		33
Operating lease cost	923		984		2,231		2,011
Short-term lease cost (1)	3,418		3,179		6,954		5,771
Variable lease cost	—		—		0		—
Total lease cost	$	4,341	$	4,348	$	9,185	$	9,063

1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of ~~$0.8~~$0.7 million ~~$— million,~~and $0.1 million ~~$1.0 million, and $1.5 million for~~during the three months ended ~~September~~June 30, 2022 and 2021, respectively, and $1.2 million and $0.2 million during the ~~one month ended September 30, 2020, the two~~six months ended ~~August 31, 2020, the nine months ended September~~June 30, ~~2021,~~2022 and ~~eight months ended August 31, 2020,~~2021, 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


	Six Months Ended June 30,
	2022		2021
	(In thousands)
Cash payments made on operating leases	$	2,190	$	2,063
Cash payments made on finance leases	$	—	$	3,216
Lease liabilities recognized in exchange for new operating lease right of use assets	$	909	$	167

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NOTE 15 – SUPERIOR INVESTMENT

On April 3, 2018, we sold 50% of the ownership interest in Superior to SP Investor Holdings, LLC (SP Investor), a holding company jointly owned by OPTrust, and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior is governed and managed under the Amended and Restated Limited Liability Company Agreement (Agreement) and Amended and Restated Master Services and Operating Agreement (MSA). The MSA was between our wholly-owned subsidiary, SPC Midstream Operating, L.L.C. (the Operator), and Superior. As the Operator, we provided 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.

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

Superior paid cash distributions of $9.5 million to each of the Members in January 2022 representing Available Cash generated during the three months ended December 31, 2021, and paid distributions to SP Investor of $10.5 million in April 2022 representing Available Cash generated during the three months ended March 31, 2022 and $13.9 million in July 2022 representing Available Cash generated during the three months ended June 30, 2022. The distributions paid to SP Investor in July 2022 reduced the remaining Drilling Commitment Adjustment Amount to $48.2 million.

Distributions paid by Superior during the three and six months ended June 30, 2021 totaled $24.7 million. Unit and SP Investor each received 50% of these distributions.

Sale Event. After April 1, 2023, either Member may initiate a sale process of Superior to a third-party or a liquidation of Superior's assets (Sale Event). In a Sale Event, the Agreement generally requires cumulative distributions to SP Investor in excess of its original $300.0 million investment sufficient to provide SP Investor a 7% internal rate of return on its capital contributions to Superior before any liquidation distribution is made to Unit. As of June 30, 2022, liquidation distributions paid first to SP Investor of $353.7 million would be required for SP Investor to reach its 7% Liquidation IRR Hurdle at which point Unit would then be entitled to receive up to $353.7 million of the remaining liquidation distributions to satisfy Unit's 7% Liquidation IRR Hurdle with any remaining liquidation distributions paid as outlined within the Agreement.

Consolidation. From April 3, 2018 to March 1, 2022, we treated Superior as a variable interest entity (VIE) because the equity holders as a group (Unit Corporation and SP Investor) lacked the power to control without the Operator. The Agreement and MSA gave us the power to direct the activities that most significantly affect Superior's operating performance through common control of the Operator. Accordingly, Unit was considered the primary beneficiary and consolidated the financial position, operating results, and cash flows of Superior.

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

We subsequently account for our investment in Superior as an equity method investment using the hypothetical liquidation book value (HLBV) method, 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. We recognized no equity earnings from our investment in Superior during the three and six months ended June 30, 2022.

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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.Estimated Fair Value of Equity Method Investment in Superior.~~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~~ As of the ~~lease.~~Effective Date, in conjunction with fresh start accounting under ASC Topic 852, Reorganizations, the estimated fair value of the net equity attributable to Unit's ownership interest in Superior was $14.8 million. Since then, Unit has received cumulative distributions from Superior of $32.6 million, which were recognized as net income attributable to Unit under the HLBV method. As of March 1, 2022, upon deconsolidation of Superior, the fair value of our retained equity method investment in Superior was estimated at $1.7 million. To estimate this fair value, we simulated paths for Superior's total equity value through the potential sales process initiation date using a Geometric Brownian Motion. The expected value (i.e., average of all simulations) of each security class was then discounted to present value using the relevant risk-free rate. The simulations reflect forecasted future cash distributions as impacted by the Drilling Commitment Adjustment Amount described above, as well as the future liquidation preference of each investor in a potential Sale Event also as described above. We consider this a Level 3 measurement within the fair value hierarchy as the discounted simulation models require the use of significant unobservable inputs.

We recognized a $13.1 million loss on deconsolidation during the three months ended March 31, 2022 as the difference between the $1.7 million estimated fair value of our retained equity method investment in Superior as of March 1, 2022 and Superior's net equity attributable to Unit's ownership interest prior to deconsolidation.

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Superior Balance Sheet Disclosure. The amounts below reflect the Superior balance sheet accounts, without elimination of intercompany receivables from and payables to Unit, consolidated in our unaudited condensed consolidated balance sheets as of December 31, 2021 which was the last reporting date as of which we consolidated the financial position of Superior:


	December 31, 2021
	(In thousands)
Current assets:
Cash and cash equivalents	$	17,246
Accounts receivable	42,628
Prepaid expenses and other	1,263
Total current assets	61,137
Property and equipment:
Gas gathering and processing equipment	274,748
Transportation equipment	2,801
	277,549
Less accumulated depreciation, depletion, amortization, and impairment	53,792
Net property and equipment	223,757
Right of use asset	3,485
Other assets	2,226
Total assets	$	290,605

Current liabilities:
Accounts payable	$	34,010
Accrued liabilities	5,292
Current operating lease liability	1,450
Current portion of other long-term liabilities	1,548
Total current liabilities	42,300
Long-term debt	19,200
Operating lease liability	2,036
Total liabilities	$	63,536

Affiliate Activity. UPC's oil and natural gas revenues with Superior totaled $19.5 million and $9.3 million during the three months ended June 30, 2022 and 2021, respectively, and $35.8 million and $17.9 million during the six months ended June 30, 2022 and 2021, respectively. UPC's gas gathering and processing expenses with Superior totaled $0.8 million and $0.9 million during the three months ended June 30, 2022 and 2021, respectively, and $1.6 million and $1.7 million during the six months ended June 30, 2022 and 2021, respectively. Portions of this activity was eliminated for the periods during which Superior was consolidated by Unit.

NOTE 1516 – 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.

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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, commercial disputes with customers, 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~~In February 2021, UPC finalized a settlement agreement 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~~$2.1 million related to a well drilled in Beaver County, ~~Oklahoma.~~Oklahoma during 2013. 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 finalized the settlement agreement while itthe case 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.

~~Table of Contents~~

~~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
Appeals.

NOTE 17 – INCOME TAXES

For the three and ~~nine~~six months ended ~~September~~June 30, 2022 and 2021, respectively, 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 differwhich differs from the statutory rate of 21.0% ~~mostly~~primarily due to changes in, and continued need of, our full valuation allowance, ~~our non-controlling interests~~changes in ~~consolidated subsidiaries,~~the warrant liability valuation, and state income taxes.

~~Deferred Tax Asset Valuation Allowance~~

~~The company has~~We 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 to zero. We maintained this conclusion as of ~~September~~June 30, ~~2021, to zero. The company~~2022 and December 31, 2021. We will continue to evaluate whether the valuation allowance is needed in future reporting periods and it will remain until ~~the company~~we 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~~us 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, sustained significant improvements in commodity prices, a sustained significant increase in rig utilization and/or rates, 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~~utilizing the tax attributes if the company recognizes taxable income. As long as ~~the company continues~~we continue to conclude that the valuation allowance against ~~its~~the 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,~~December 31, 2021, ~~and~~the company had an expected federal net operating loss carryforward of $385.5 million after consideration of the tax attribute reductions of IRC Section 108, ~~and~~ finalization of the company’s 2020 federal income tax return, and pending finalization of the ~~company has an expected~~company's 2021 federal ~~net operating loss carryforward of $420.3 million~~income tax return of which ~~$225.3~~$190.5 million is subject to expiration between ~~2021~~2036 and 2037. As of December 31, 2021, our tax basis in UPC's properties was approximately $475.0 million.

NOTE 18 – TRANSACTIONS WITH RELATED PARTIES

One current director, Robert Anderson, also serves as an executive with GBK Corporation, a holding company with numerous energy and industry subsidiaries and affiliates, including Kaiser Francis Oil Company. The company in the ordinary course of business, made payments for working interests, joint interest billings, and product purchases to, and received payments for working interests, drilling services, and joint interest billings from, Kaiser Francis Oil Company. Payments made to Kaiser Francis Oil Company totaled $0.7 million and $0.6 million while payments received totaled $3.6 million and $0.3 million during the three months ended June 30, 2022 and 2021, respectively, and payments made to Kaiser Francis Oil Company totaled $4.2 million and $1.0 million while payments received totaled $7.5 million and $1.3 million during the six months ended June 30, 2022 and 2021, respectively.

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One former director, G. Bailey Peyton IV, also serves as Manager and 99.5% owner of Peyton Royalties, LP, a family-controlled limited partnership that owns royalty rights in wells in several states. The company in the ordinary course of business, paid royalties, or lease bonuses, primarily due to its status as successor in interest to prior transactions and as operator of the wells involved and, sometimes, as lessee, regarding certain wells in which Mr. Peyton, members of Mr. Peyton's family, and Peyton Royalties, LP have an interest. Such payments totaled $0.1 million and $0.1 million during the three months ended June 30, 2022 and 2021, respectively, and $0.3 million and $0.2 million during the six months ended June 30, 2022 and 2021, respectively.

NOTE 1819 – INDUSTRY SEGMENT INFORMATION

We have 3 main business segments offering different products and services within the energy industry:

•Oil and natural gas

•~~Contract drilling, and~~

•~~Mid-Stream~~

~~Our~~ - the oil and natural gas segment is engaged in the acquisition, development, and production of oil, NGLs, and natural gas properties. ~~The~~

•Contract drilling - the contract drilling segment is engaged in the land contract drilling of oil and natural gas ~~wells and~~wells.

•Mid-Stream - the mid-stream segment ~~is engaged in the buying, selling, gathering, processing,~~buys, sells, gathers, processes, and ~~treating of~~treats natural gas and ~~NGLs.~~NGLs for third parties and for our own account. We presently own 50% of this subsidiary, and subsequent to the deconsolidation of Superior as of March 1, 2022 (as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment), we will continue to include our equity method investment in Superior and related earnings in our mid-stream segment.

We evaluate each consolidated 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 or other operations 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)

~~_______________________~~


	Three Months Ended June 30, 2022
	Oil and Natural Gas		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	100,896	$	—	$	—	$	—	$	16	$	100,912
Contract drilling	—		33,642		—		—		—		33,642

Total revenues	100,896		33,642		—		—		16		134,554
Expenses:
Operating costs:
Oil and natural gas	27,603		—		—		—		16		27,619
Contract drilling	—		25,763		—		—		—		25,763

Total operating costs	27,603		25,763		—		—		16		53,382
Depreciation, depletion, and amortization	4,027		1,558		—		76		—		5,661

Total expenses	31,630		27,321		—		76		16		59,043

General and administrative	—		—		—		7,421		—		7,421
Gain on disposition of assets	(25)		(2,041)		—		—		—		(2,066)
Income (loss) from operations	69,291		8,362		—		(7,497)		—		70,156
Gain on derivatives	—		—		—		2,609		—		2,609
Gain on change in fair value of warrants	—		—		—		7,289		—		7,289


Reorganization items, net	—		—		—		(39)		—		(39)
Interest, net	—		—		—		(97)		—		(97)
Other	13		9		—		153		—		175
Income before income taxes	$	69,304	$	8,371	$	—	$	2,418	$	—	$	80,093

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.

~~Table of Contents~~

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.~~

3531

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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)

~~_______________________~~


	Three Months Ended June 30, 2021
	Oil and Natural Gas		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	59,776	$	—	$	—	$	—	$	(17,806)	$	41,970
Contract drilling	—		18,061		—		—		—		18,061
Gas gathering and processing	—		—		66,323		—		7,703		74,026
Total revenues	59,776		18,061		66,323		—		(10,103)		134,057
Expenses:
Operating costs:
Oil and natural gas	16,350		—		—		—		(863)		15,487
Contract drilling	—		14,080		—		—		—		14,080
Gas gathering and processing	—		—		55,176		—		(10,120)		45,056
Total operating costs	16,350		14,080		55,176		—		(10,983)		74,623
Depreciation, depletion, and amortization	6,476		1,570		8,064		254		—		16,364
Total expenses	22,826		15,650		63,240		254		(10,983)		90,987
General and administrative	—		—		—		4,871		880		5,751
Gain on disposition of assets	(67)		(1,618)		—		(25)		—		(1,710)
Income (loss) from operations	37,017		4,029		3,083		(5,100)		—		39,029
Loss on derivatives	—		—		—		(42,400)		—		(42,400)
Loss on change in fair value of warrants	—		—		—		(3,574)		—		(3,574)
Reorganization items, net	—		—		—		(1,852)		—		(1,852)
Interest, net	—		—		641		(1,128)		—		(487)
Other	34		11		(850)		(26)		—		(831)
Income (loss) before income taxes	$	37,051	$	4,040	$	2,874	$	(54,080)	$	—	$	(10,115)

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

3632

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		Predecessor
		Eight Months Ended August 31, 2020													Six Months Ended June 30, 2022
		Oil and Natural Gas		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations		Total Consolidated			Oil and Natural Gas		Contract Drilling		Mid-Stream (2)		Corporate and Other		Eliminations (2)		Total Consolidated
		(In thousands)													(In thousands)
Revenues: (1)	Revenues: (1)													Revenues: (1)
Oil and natural gas	Oil and natural gas	$	103,443	$	—	$	—	$	—	$	(4)	$	103,439	Oil and natural gas	$	188,478	$	—	$	—	$	—	$	(10,756)	$	177,722
Contract drilling	Contract drilling	—		73,519		—		—		—		73,519		Contract drilling	—		62,524		—		—		0		62,524
Gas gathering and processing	Gas gathering and processing	—		—		114,531		—		(14,532)		99,999		Gas gathering and processing	—		0		83,198		—		(525)		82,673
Total revenues	Total revenues	103,443		73,519		114,531		—		(14,536)		276,957		Total revenues	188,478		62,524		83,198		—		(11,281)		322,919
Expenses:	Expenses:													Expenses:
Operating costs:	Operating costs:													Operating costs:
Oil and natural gas	Oil and natural gas	119,664		—		—		—		(1,973)		117,691		Oil and natural gas	51,603		—		—		—		(509)		51,094
Contract drilling	Contract drilling	—		51,811		—		—		(1)		51,810		Contract drilling	—		52,000		—		—		—		52,000
Gas gathering and processing	Gas gathering and processing	—		—		80,607		—		(12,562)		68,045		Gas gathering and processing	—		—		73,771		—		(11,383)		62,388
Total operating costs	Total operating costs	119,664		51,811		80,607		—		(14,536)		237,546		Total operating costs	51,603		52,000		73,771		—		(11,892)		165,482
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	68,762		15,544		29,371		1,819		—		115,496		Depreciation, depletion, and amortization	8,075		3,092		5,614		150		—		16,931
Impairments		393,726		410,126		63,962		—		—		867,814

Impairment														Impairment	—		—		—		—		—		—
Total expenses	Total expenses	582,152		477,481		173,940		1,819		(14,536)		1,220,856		Total expenses	59,678		55,092		79,385		150		(11,892)		182,413
Loss on abandonment of assets		17,641		1,092		—		—		—		18,733

General and administrative	General and administrative	—		—		—		42,766		—		42,766		General and administrative	—		—		—		13,336		611		13,947
(Gain) loss on disposition of assets	(Gain) loss on disposition of assets	(160)		(1,390)		(18)		1,479		—		(89)		(Gain) loss on disposition of assets	(79)		(4,165)		—		3		—		(4,241)
Loss from operations		(496,190)		(403,664)		(59,391)		(46,064)		—		(1,005,309)
Income (loss) from operations														Income (loss) from operations	128,879		11,597		3,813		(13,489)		—		130,800
Loss on derivatives	Loss on derivatives	—		—		—		(10,704)		—		(10,704)		Loss on derivatives	—		—		—		(61,467)		—		(61,467)
Write-off of debt issuance costs		—		—		—		(2,426)		—		(2,426)

Loss on change in fair value of warrants														Loss on change in fair value of warrants	—		—		—		(29,323)		—		(29,323)
Loss on deconsolidation of Superior														Loss on deconsolidation of Superior	—		—		—		(13,141)		—		(13,141)
Reorganization items, net	Reorganization items, net	15,504		(183,664)		(71,016)		373,151		—		133,975		Reorganization items, net	—		—		—		(42)		—		(42)
Interest, net	Interest, net	—		—		(1,888)		(20,936)		—		(22,824)		Interest, net	—		—		(179)		(192)		—		(371)
Other	Other	458		1,449		50		77		—		2,034		Other	721		28		17		166		—		932
Income (loss) before income taxes	Income (loss) before income taxes	$	(480,228)	$	(585,879)	$	(132,245)	$	293,098	$	—	$	(905,254)	Income (loss) before income taxes	$	129,600	$	11,625	$	3,651	$	(117,488)	$	—	$	27,388

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

2.Includes Superior activity for the two months prior to the March 1, 2022 deconsolidation, as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment.

Table of Contents


	Six Months Ended June 30, 2021
	Oil and Natural Gas		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	114,801	$	—	$	—	$	—	$	(17,807)	$	96,994
Contract drilling	—		33,735		—		—		—		33,735
Gas gathering and processing	—		—		125,932		—		(1,707)		124,225
Total revenues	114,801		33,735		125,932		—		(19,514)		254,954
Expenses:
Operating costs:
Oil and natural gas	36,343		—		—		—		(1,707)		34,636
Contract drilling	—		25,951		—		—		—		25,951
Gas gathering and processing	—		—		104,286		—		(19,567)		84,719
Total operating costs	36,343		25,951		104,286		—		(21,274)		145,306
Depreciation, depletion, and amortization	14,131		3,145		16,096		503		—		33,875
Impairment	—		—		—		—		—		—
Total expenses	50,474		29,096		120,382		503		(21,274)		179,181
Loss on abandonment of assets	—		—		—		—		—		—
General and administrative	—		—		—		11,160		1,760		12,920
(Gain) loss on disposition of assets	(87)		(2,146)		75		(24)		—		(2,182)
Income (loss) from operations	64,414		6,785		5,475		(11,639)		—		65,035
Loss on derivatives	—		—		—		(65,231)		—		(65,231)
Loss on change in fair value of warrants	—		—		—		(3,574)		—		(3,574)
Reorganization items, net	—		—		—		(2,988)		—		(2,988)
Interest, net	—		—		(416)		(2,777)		—		(3,193)
Other	90		16		(839)		(22)		—		(755)
Income (loss) before income taxes	$	64,504	$	6,801	$	4,220	$	(86,231)	$	—	$	(10,706)

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

~~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.

~~Table of Contents~~

~~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

~~Table of Contents~~

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)

~~Table of Contents~~

~~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~~2021 Form 10-K filed with the SEC on March 31, ~~2021.~~2022.

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 produces, develops, ~~acquires,~~ and ~~produces~~acquires 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~~hold a 50% ~~of this subsidiary.~~investment in Superior.

Oil and Natural Gas

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~~activities. We also anticipate continuing to hedge a portion 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 executeour future production depending on ~~low cost capital projects to enhance production and reserves in this favorable price environment.~~future market pricing among other factors.

Contract Drilling

In our contract drilling segment, ~~management reduced the number~~we are focused on maintaining utilization of our BOSS and SCR 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~~a safe and efficient manner. All 14 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.~~operating in addition to three of our SCR drilling rigs. We ~~also plan~~continue to ~~continue seeking~~evaluate opportunities to ~~divest non-core, idle~~place one or more of our four non-operating SCR drilling ~~equipment.~~rigs back in service.

Mid-Stream

In our mid-stream segment, ~~we are~~Superior is focused on continuing to generate predictable free cash flows with limited exposure to commodity ~~prices. We also plan~~prices in addition to ~~continue~~ seeking business development opportunities in ~~our~~its 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~~ We hold a 50% investment in Superior, and subsequent to the deconsolidation of Superior as of March 1, 2022, we report our ~~emergence from the Chapter 11 Cases on September 3, 2020, we adopted fresh start accounting~~ownership interest as ~~required by US GAAP. As a result~~an equity method investment. The following discussion of financial condition and results of operations pertaining to our mid-stream segment as of the ~~application~~second quarter of ~~fresh start accounting, as well as~~2022 relates to the ~~effects~~two months of ~~the implementation of the Plan, our~~ consolidated ~~financial statements after August 31, 2020 are not comparable with our consolidated financial statements~~results prior to ~~that date.~~deconsolidation as of March 1, 2022.

Recent Developments

~~COVID-19 Pandemic and~~ Commodity Price Environment and COVID-19 Pandemic

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

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

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

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

~~_________________________~~

1.~~NGLs~~NGL prices reflect ~~a weighted-average, based on production, of~~the monthly average Mont Belvieu ~~and Conway prices.~~price.

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Stock ~~Repurchase Program~~Repurchases

In June 2021, we repurchased an aggregate of 600,000 shares of our common stock from the ~~Board~~Lenders (as defined in Note 9 - Long-Term Debt and Other Long-Term Liabilities) which received these shares as an exit fee during our reorganization. The Lenders were paid $15.00 per share for their respective shares, for an aggregate cash purchase price of $9.0 million.

As of ~~September~~June 30, ~~2021, the company has~~2022, we had 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~~1,519,392 shares under the repurchase program at an average share price of ~~$34.80~~$36.00 for an aggregate purchase price of ~~$24.8 million bringing~~$54.7 million. Subsequent to June 30, 2022, we have repurchased an additional 75,000 shares under the repurchase program for an aggregate ~~shares repurchased under all methods since the Effective Date to 1,739,963 shares.~~purchase price of $3.8 million.

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

~~As contemplated by~~The cumulative number of shares repurchased as of June 30, 2022 totaled 2,197,392.

Superior MSA and LLCA amendments

Effective March 1, 2022, the ~~Plan, the company distributed 683,038 and 161,328 additional shares of New Common Stock to holders~~employees of the ~~subordinated notes claims on July 26, 2021~~Operator were transferred to Superior and ~~October 20, 2021, respectively, as a result of~~ the ~~pro rata distribution of shares of New Common Stock out of~~MSA was amended and restated to remove the ~~equity reserves established under~~operating services the ~~Plan for certain disputed claims against the company and UPC. The shares of New Common Stock were distributed pursuant~~Operator was providing 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). PursuantSuperior. There was no change to the ~~Plan, all shares~~monthly service fee for shared services. We no longer consolidate the financial position, operating results, and cash flows of ~~New Common Stock~~Superior as of, and subsequent to, March 1, 2022. We recognized a $13.1 million loss on deconsolidation during the six months ended June 30, 2022 as the difference between the $1.7 million estimated fair value of our retained equity method investment in Superior as of March 1, 2022 and Superior's net equity attributable to Unit's ownership interest prior to deconsolidation. We subsequently account for our investment in Superior as an equity method investment using the hypothetical liquidation book value (HLBV) method 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 ~~distributed in book-entry form through~~liquidated at book value at the ~~facilities~~end of ~~The Depository Trust Company (DTC)~~each period, adjusted for any contributions made and distributions received during the period.

Warrants

Each holder of ~~the Old~~Unit common stock outstanding (Old Common ~~Stock outstanding~~Stock) before the ~~Effective Date~~September 3, 2020 emergence from bankruptcy (Emergence Date) that did not opt out of the release under the ~~Plan,~~Chapter 11 plan of reorganization filed with the bankruptcy court on June 9, 2020 is entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant ~~will initially be~~is exercisable for one share of ~~New Common Stock,~~company 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 Warrantswarrants 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~~dissolution or winding up of the company. As of June 30, 2022, the company ~~(such earliest date,~~has issued 1,822,203 warrants. See Note 5 - Capital Stock for additional discussion on warrant provisions.

Pursuant to the ~~Expiration Date). Each Warrant that is not exercised on or before the Expiration Date will expire, and all rights under that Warrant and~~terms of the Warrant Agreement, ~~will cease on~~ the ~~Expiration Date.~~company determined the initial exercise price of the warrants to be $63.74. On April 7, 2022, the company delivered notice of the initial exercise price to the Warrant Agent and the warrants became exercisable for shares of the company’s common stock. On or about April 25, 2022, the warrants began trading over-the-counter under the symbol "UNTCW".

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 near-term and long-term financial condition and liquidity primarily depend on the cash flow from our operations and ~~borrowings under our~~ credit ~~agreements.~~agreement borrowings. The principal factors determining our cash flow from operations 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~~utilization of our drilling rigs and the rates we receive for those drilling rigs; and

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•the fees and margins ~~we obtain~~that Superior obtains from ~~our~~its natural gas gathering and processing contracts.

We ~~currently~~ expect that cash and cash equivalents, cash ~~generated~~flow from operations, and available ~~funds~~borrowing capacity under the Exit credit agreement ~~and the Superior credit agreement are~~will be adequate to ~~cover~~support our ~~liquidity~~working capital, capital expenditures, potential dividend distributions, discretionary stock repurchases, and other cash requirements for at least the next 12 ~~months.~~months and we are not aware of any indications that they will not be adequate for the foreseeable periods thereafter.

~~Below is a summary of certain financial information for~~The table below summarizes cash flow activity during 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

~~_________________________~~


	Six Months Ended June 30,				Percent Change (1)
	2022		2021
	(In thousands except percentages)
Net cash provided by operating activities	$	88,125	$	73,965	19	%
Net cash provided by (used in) investing activities	(13,882)		7,605		NM
Net cash used in financing activities	(22,755)		(87,295)		74	%
Net increase (decrease) in cash and cash equivalents	$	51,488	$	(5,725)

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 volume of oil, ~~NGL,~~NGLs, and natural gas we produce, settlements of commodity derivative contracts, third-party ~~use for~~utilization of our drilling rigs and Superior's mid-stream services, and the rates ~~we can charge~~charged for those drilling and mid-stream services. Our cash flows from operating activities are also affected by changes in working capital.

Net cash provided by ~~(used in)~~ operating activities induring the first ~~nine~~six months of ~~2021~~2022 increased by ~~$69.8~~$14.2 million as compared to the first ~~nine~~six months of ~~2020. The increase resulted from~~2021 primarily due to increased operating profit ~~in all three~~from our oil and natural gas and contract drilling segments, partially offset by higher payments on derivative settlements, net changes in operating assets and liabilities related to the timing of cash receipts and ~~disbursements.~~disbursements, and lower operating profit from our mid-stream segment reflecting the March 1, 2022 deconsolidation of Superior.

Cash Flows from Investing Activities

We ~~have historically dedicated~~anticipate using a ~~substantial~~ portion of our free cash flows for capital ~~budgets~~expenditures related to our ~~exploration for~~development 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~~decreased by ~~$71.4~~$21.5 million ~~for~~during the first ~~nine~~six months of ~~2021~~2022 compared to the first ~~nine~~six months of ~~2020. The change was~~2021 primarily due to the deconsolidation of Superior's cash and cash equivalents, higher capital expenditures, and lower 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.~~assets.

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Cash Flows from Financing Activities

Net cash ~~provided by (used in)~~used in financing activities decreased by ~~$141.0~~$64.5 million for the first ~~nine~~six months of ~~2021~~2022 compared to the first ~~nine~~six months of ~~2020. The decrease was~~2021 primarily due to ~~higher~~the absence of net payments on ~~our~~ credit agreements and finance leases as well as lower ~~net borrowings under our credit agreements,~~ distributions made by Superior to non-controlling interests, ~~the repurchase~~partially offset by higher repurchases of common stock. A portion of future cash flows and cash and cash equivalents may be used for future shareholder return activities, including stock repurchases and ~~lower bank overdrafts.~~cash distributions.

~~At September~~As of June 30, ~~2021,~~2022, we had unrestricted cash and cash equivalents totaling ~~$49.6~~$115.6 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~~Table of Contents

The following table summarizes certain financial condition and liquidity information as of ~~September 30:~~the dates identified below:

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


	June 30, 2022		June 30, 2021
	(In thousands)
Working capital	$	79,799	$	(38,200)
Current portion of long-term debt	$	—	$	—
Long-term debt	$	—	$	35,000
Shareholders’ equity attributable to Unit Corporation	$	260,368	$	155,562

Working Capital

~~Typically, our~~Our working capital balance typically fluctuates ~~in part, because of~~due to 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~~fair values of our derivative ~~activity.~~positions. We had positive working capital of $79.8 million and negative working capital of ~~$30.4 million and positive working capital of $21.6~~$38.2 million as of ~~September~~June 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The ~~decrease~~increase 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~~receivable, net as well as the absence of ~~our~~the warrant liability and lower accrued liabilities and payables, partially offset by higher current commodity derivative liabilities. Our commodity derivative contracts decreased working capital by ~~$60.0~~$48.8 million as of ~~September~~June 30, ~~2021~~2022 and ~~increased~~decreased working capital by ~~$1.3~~$38.0 million as of ~~September~~June 30, ~~2020.~~2021.

~~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, among others, 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.

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

On July 1, 2022, the RBL Facility borrowing base was automatically reduced to $31.3 million as a result of closing the Texas Gulf Coast properties sale discussed in Note 4 - Divestitures.

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~~On April 29, 2022, Superior entered into an Amended and Restated Credit Agreement for a four-year, $135.0 million senior secured revolving credit facility with an option to increase the credit amount up to $200.0 million, subject to certain conditions (Amended Superior credit ~~agreement is March 10, 2023. 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.~~agreement).

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Capital Requirements

Oil and Natural Gas Segment Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward growth. Our decisions to increase our oil, NGLs, and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential, and opportunities to obtain financing, which provide us flexibility in deciding when and if to incur these costs. We participated in the completion of 16 gross wells (0.64 net wells) drilled by other operators during the first six months of 2022 compared to 10 gross wells (0.77 net wells) ~~drilled by other operators in~~during the first ~~nine~~six 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.~~2021.

Capital expenditures ~~for~~including oil and gas properties on the full cost method for the first ~~nine~~six months of ~~2021~~2022 by this segment totaled $9.2 million, excluding a ~~$1.6~~$1.4 million increase in the ARO liability, ~~totaled $7.1 million. Capital expenditures for the first nine months of 2020,~~compared to $5.9 million, excluding ~~$0.4 million for acquisitions and~~ a ~~$28.2~~$1.1 million reduction in the ARO liability, ~~totaled $10.3 million.~~during the first six months of 2021.

On ~~June 25, 2021,~~July 1, 2022, the company ~~entered into a purchase and~~closed on the sale ~~agreement to which we agreed to sell substantially all~~ of ~~our~~certain wells and related leases near the ~~leases related thereto located near Oklahoma City, Oklahoma~~Texas Gulf Coast for ~~$19.5~~cash proceeds of $43.7 million, subject to customary ~~closing and~~ post-closing ~~adjustments. The divestiture closed~~adjustments based on ~~August 16, 2021, with~~ an effective date of ~~May~~April 1, ~~2021. The~~2022. These proceeds will reduce the net book value of our full cost pool with no gain or loss recognized as the sale ~~of these assets~~ did not result in a significant alteration of the full cost pool.

On ~~March 30,~~May 6, 2021, the company ~~entered into a purchase and~~closed on the sale ~~agreement to which we agreed to sell~~of substantially all of our wells and the leases related thereto located in Reno and Stafford Counties, Kansas for proceeds of $7.1 million, ~~subject to customary closing and~~excluding 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.

Net proceeds for the sale of other non-core oil and natural gas assets totaled $2.3 million and $4.4 million during the six months ended June 30, 2022 and 2021, respectively. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sales did not result in a significant alteration of the full cost pool.

Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. ~~For 2021,~~Near term capital expenditures are expected to primarily be for maintenance capital on operating drilling rigs. We also ~~plan~~continue to pursue the disposal or sale of our non-core, idle drilling rig fleet. ~~We incurred $0.9 million in~~Contract drilling capital expenditures totaled $4.2 million during the first ~~nine~~six months of ~~2021,~~2022 compared to ~~$4.0~~$0.5 million ~~for capital expenditures~~ during the first ~~nine~~six months of ~~2020.~~2021.

We sold non-core contract drilling assets for proceeds of ~~$8.2~~$6.4 million ~~net of related expenses, during the nine months ended September 30, 2021, compared to proceeds of $4.8~~and $3.9 million during the ~~eight~~six months ended ~~August 31, 2020~~June 30, 2022 and ~~none during the one month ended September 30, 2020.~~2021, respectively. These proceeds resulted in net gains of ~~$5.2~~$4.2 million and $2.1 million during the ~~nine~~six months ended ~~September~~June 30, 2022 and 2021, ~~compared to $1.4 million during the eight months ended August 31, 2020.~~respectively.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. ~~During~~Superior incurred $1.2 million in consolidated capital expenditures during the first ~~nine~~six months of ~~2021, our mid-stream segment incurred $8.6 million in capital expenditures as~~2022 compared to ~~$10.2~~$4.1 million induring the first ~~nine~~six 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.2021.

~~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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Derivative Activities

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~~As of June 30, ~~2021,~~2022, based on our ~~third~~second quarter ~~2021~~2022 average daily production, the approximated percentages of our production under derivative contracts are as follows:


		2021	2022	2023		2022	2023
Daily oil production	Daily oil production	87%	64%	36%	Daily oil production	86%	45%
Daily natural gas production	Daily natural gas production	63%	54%	30%	Daily natural gas production	75%	36%

~~The use of~~Using derivative ~~transactions carries with it~~instruments involves the risk that the counterparties ~~may not be able to~~cannot meet ~~their~~the financial ~~obligations under~~terms of the transactions. ~~Based on our September 30, 2021 evaluation, we believe the~~We considered this non-performance risk ~~of non-performance by~~regarding our counterparties ~~is not material. At September~~and our own non-performance risk in our derivative valuation at June 30, ~~2021, the~~2022 and determined there was no material risk at that time. The fair ~~values~~value of the net liabilities we had with ~~each~~Bank of Oklahoma, our only commodity derivative counterparty, was $66.1 million as of June 30, 2022.

Warrants. Prior to the determination of the ~~counterparties~~initial exercise price, we recognized the fair value of the warrants as a derivative liability on our unaudited condensed consolidated balance sheets with changes in the liability reported as gain (loss) on change in fair value of warrants in our unaudited condensed consolidated statements of operations. On April 7, 2022, the company delivered notice of the initial $63.74 exercise price resulting in the warrants meeting the definition of an equity instrument. Accordingly, we recognized the change in the fair value of the warrant liability in our unaudited condensed consolidated statements of operations and reclassified the $49.1 million warrant liability to ~~our commodity derivative transactions~~capital in excess of par value on the unaudited condensed consolidated balance sheets as of April 7, 2022. The warrants will continue to be reported as capital in excess of par and are ~~as follows:~~no longer subject to future fair value adjustments. On or about April 25, 2022, the warrants began trading over-the-counter under the symbol "UNTCW".


	~~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)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In thousands)
Gain (loss) on derivatives	$	2,609	$	(42,400)	$	(61,467)	$	(65,231)
Cash settlements paid on commodity derivatives	(32,884)		(6,403)		(54,123)		(9,707)
Gain (loss) on derivatives less cash settlements paid on commodity derivatives	$	35,493	$	(35,997)	$	(7,344)	$	(55,524)

Gain (loss) on change in fair value of warrants	$	7,289	$	(3,574)	$	(29,323)	$	(3,574)

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Results of Operations

~~Quarter Ended September~~Three months ended June 30, ~~2021~~2022 versus ~~Quarter Ended September~~three months ended June 30, ~~2020~~2021

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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	Three Months Ended June 30,						Change			Percent Change (1)
	2022			2021
	(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations	$	134,538		$	144,160		$	(9,622)		(7)	%
Total revenue, after inter-segment eliminations	$	134,554		$	134,057		$	497		—	%
Net income (loss)	$	80,093		$	(10,115)		$	90,208		NM
Net income (loss) attributable to non-controlling interest	$	—		$	2,879		$	(2,879)		(100)	%
Net income (loss) attributable to Unit Corporation	$	80,093		$	(12,994)		$	93,087		NM

Oil and Natural Gas:
Revenue, before inter-segment eliminations	$	100,896		$	59,776		$	41,120		69	%
Operating costs, before inter-segment eliminations	$	27,603		$	16,350		$	11,253		69	%
Average oil price (Bbl)	$	56.28		$	48.38		$	7.90		16	%
Average oil price excluding derivatives (Bbl)	$	110.29		$	64.38		$	45.91		71	%
Average NGLs price (Bbl)	$	34.72		$	17.95		$	16.77		93	%
Average NGLs price excluding derivatives (Bbl)	$	34.72		$	17.95		$	16.77		93	%
Average natural gas price (Mcf)	$	4.24		$	2.98		$	1.26		42	%
Average natural gas price excluding derivatives (Mcf)	$	6.62		$	3.00		$	3.62		121	%
Oil production (MBbls)	309��			389			(80)			(21)	%
NGL production (MBbls)	620			662			(42)			(6)	%
Natural gas production (MMcf)	6,821			7,543			(722)			(10)	%


Contract Drilling:
Revenue, before inter-segment eliminations	$	33,642		$	18,061		$	15,581		86	%
Operating costs, before inter-segment eliminations	$	25,763		$	14,080		$	11,683		83	%



Average number of drilling rigs in use	16.3			10.0			6.3			63	%
Total drilling rigs available for use at the end of the period	21			21			—			—	%

Average dayrate on daywork contracts - BOSS Rigs	$	21,955		$	20,063		$	1,892		9	%
Average dayrate on daywork contracts - SCR Rigs	$	18,217		$	14,034		$	4,183		30	%

Mid-Stream: (2)
Revenue, before inter-segment eliminations	$	—		$	66,323		$	(66,323)		(100)	%
Operating costs, before inter-segment eliminations	$	—		$	55,176		$	(55,176)		(100)	%








Corporate and Other:

General and administrative expense, before inter-segment eliminations	$	7,421		$	4,871		$	2,550		52	%


Other income (expense):

Interest expense, net	$	(97)		$	(487)		$	390		(80)	%

Reorganization items, net	$	(39)		$	(1,852)		$	1,813		(98)	%
Gain (loss) on derivatives	$	2,609		$	(42,400)		$	45,009		106	%
Gain (loss) on change in fair value of warrants	$	7,289		$	(3,574)		$	10,863		NM


Income tax benefit	$	—		$	—		$	—		—	%
Average interest rate on long-term debt outstanding	—		%	6.5		%	(6.5)		%	(100)	%
Average long-term debt outstanding	$	—		$	62,646		$	(62,646)		(100)	%

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

2.Absence of mid-stream activity during the three months ended June 30, 2022 reflects the March 1, 2022 deconsolidation of Superior.

Table of Contents

Oil and Natural Gas

Oil and natural gas revenues increased ~~$24.6~~$41.1 million or ~~59% in~~69% during the ~~third~~second quarter of ~~2021~~2022 as compared to the ~~third~~second quarter of ~~2020~~2021 primarily due to higher commodity prices, partially offset by lower production volumes. ~~In the third quarter of 2021, as compared~~Including derivatives settled, average oil prices increased 16% to ~~the third quarter of 2020, oil~~$56.28 per barrel, average natural gas prices increased 42% to $4.24 per Mcf, and NGLs prices increased 93% to $34.72 per barrel. Oil production decreased ~~35%~~21%, natural gas production decreased ~~25%~~10%, and NGLs production decreased ~~23%~~6%. 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~~increased $11.3 million or 3%69% between the comparative ~~third~~second quarters of ~~2021~~2022 and ~~2020~~2021 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.~~

taxes on higher revenues, employee separation benefits, and lease operating expenses.

Contract Drilling

Drilling revenues increased ~~$7.1~~$15.6 million or ~~58% in~~86% during the ~~third~~second quarter of 2022 compared to the second quarter of 2021 ~~versus the third quarter of 2020. The increase was driven~~ primarily bydue to an increase in the average number of rigs in use from ~~5.1~~10.0 in the ~~third~~second quarter of ~~2020~~2021 to ~~11.0~~16.3 in the ~~third~~second quarter of ~~2021.~~2022 as well as increases to the average dayrates on daywork contracts of 9% and 30% on BOSS rigs and SCR rigs, respectively.

Drilling operating costs increased ~~$7.0~~$11.7 million or 83% between the comparative ~~third~~second quarters of ~~2021~~2022 and ~~2020. The change was~~2021 primarily due to an increase in the average number of operating rigs as well as $2.3 million of transportation and ~~the associated~~ start up costs associated with bringing stacked rigs back into service.

Mid-Stream

Our mid-stream revenues ~~increased $40.6~~decreased $66.3 million or ~~79% in~~100% during the ~~third~~second quarter of ~~2021~~2022 as compared to the ~~third~~second quarter of ~~2020 primarily~~2021 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~~absence of ~~our major processing systems. Gas gathered volumes per day decreased 11% between~~activity as a result of the ~~comparative quarters due to declining volumes and fewer new well connections.~~March 1, 2022 deconsolidation of Superior.

Operating costs ~~increased 43.1~~decreased $55.2 million or ~~128% in~~100% during the ~~third~~second quarter of 2022 compared to the second quarter of 2021 ~~compared~~due to the ~~third quarter~~absence of ~~2020 primarily due to higher gas, NGL, and condensate prices, partially offset by lower purchase volumes.~~activity as a result of the March 1, 2022 deconsolidation of Superior.

General and Administrative

Corporate general and administrative expenses ~~decreased $2.7~~increased $2.6 million or ~~39% in~~52% during the ~~third~~second quarter of 2022 compared to the second 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~~employee separation ~~benefits recognized in the third quarter of 2020.~~benefits.

~~Other Income (Expense)~~Interest Expense, Net

Interest expense, net decreased ~~$2.1~~$0.4 million between the comparative ~~third~~second quarters of ~~2021~~2022 and ~~2020~~2021 primarily due to ~~an 88%~~a 100% decrease in average long-term debt ~~outstanding, partially offset by a higher average interest rate.~~outstanding. 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~~$62.6 million induring the ~~third~~second quarter of ~~2021~~2022 compared to the ~~third~~second quarter of ~~2020~~2021 primarily due to payments made under the Exit credit agreement ~~partially offset by borrowings under~~and the ~~Superior credit agreement.~~deconsolidation of Superior's outstanding long-term debt.

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~~Gain (Loss) on Derivatives

~~Loss~~The $45.0 million favorable change in gain (loss) on derivatives ~~increased by $39.4 million~~between the comparative second quarters of 2022 and 2021 is primarily due to ~~increases in forward prices used to estimate~~favorable pricing changes on unsettled commodity derivative positions and new commodity derivative positions executed during the ~~fair value in mark-to-market accounting.~~second quarter of 2022, partially offset by higher settlement payments driven by higher average pricing.

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Loss on Change in Fair Value of Warrants

~~Loss~~The $10.9 million favorable change in gain (loss) on change in fair value of warrants ~~increased by $9.1 million~~between the comparative second quarters of 2022 and 2021 is primarily due to changes in the underlying assumptions used to estimate the fair value, including ~~estimated strike price,~~ entity value, volatility, duration to exercise, and other inputs.

Income Tax Benefit

We did not record an income tax benefit induring the ~~third~~second quarter of ~~2021 compared to $4.8 million in~~2022 or during the ~~third~~second quarter of ~~2020~~2021 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~~Six months ended June 30, 2022 versus six months ended June 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) %

~~_________________________~~


	Six Months Ended June 30,						Change			Percent Change (1)
	2022			2021
	(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations	$	334,200		$	274,468		$	59,732		22	%
Total revenue, after inter-segment eliminations	$	322,919		$	254,954		$	67,965		27	%
Net income (loss)	$	27,388		$	(10,706)		$	38,094		NM
Net income (loss) attributable to non-controlling interest	$	(5,828)		$	4,225		$	(10,053)		NM
Net income (loss) attributable to Unit Corporation	$	33,216		$	(14,931)		$	48,147		NM

Oil and Natural Gas:
Revenue, before inter-segment eliminations	$	188,478		$	114,801		$	73,677		64	%
Operating costs, before inter-segment eliminations	$	51,603		$	36,343		$	15,260		42	%
Average oil price (Bbl)	$	58.23		$	47.82		$	10.41		22	%
Average oil price excluding derivatives (Bbl)	$	100.03		$	60.12		$	39.91		66	%
Average NGLs price (Bbl)	$	33.82		$	17.95		$	15.87		88	%
Average NGLs price excluding derivatives (Bbl)	$	33.82		$	17.95		$	15.87		88	%
Average natural gas price (Mcf)	$	3.78		$	2.87		$	0.91		32	%
Average natural gas price excluding derivatives (Mcf)	$	5.60		$	2.86		$	2.74		96	%
Oil production (MBbls)	714			801			(87)			(11)	%
NGL production (MBbls)	1,233			1,303			(70)			(5)	%
Natural gas production (MMcf)	13,336			14,946			(1,610)			(11)	%

Contract Drilling:
Revenue, before inter-segment eliminations	$	62,524		$	33,735		$	28,789		85	%
Operating costs, before inter-segment eliminations	$	52,000		$	25,951		$	26,049		100	%
Average number of drilling rigs in use	15.9			9.7			6.2			64	%
Total drilling rigs available for use at the end of the period	21			21			—			—	%

Average dayrate on daywork contracts - BOSS Rigs	$	21,344		$	20,197		$	1,147		6	%
Average dayrate on daywork contracts - SCR Rigs	$	17,119		$	13,651		$	3,468		25	%

Mid-Stream: (2)
Revenue, before inter-segment eliminations	$	83,198		$	125,932		$	(42,734)		(34)	%
Operating costs, before inter-segment eliminations	$	73,711		$	104,286		$	(30,575)		(29)	%
Gas gathered--Mcf/day	348,859			296,396			52,463			18	%
Gas processed--Mcf/day	146,368			124,285			22,083			18	%
Gas liquids sold--gallons/day	456,700			425,277			31,423			7	%



Corporate and Other:
General and administrative expense, before inter-segment eliminations	$	13,336		$	11,160		$	2,176		19	%
Other income (expense):
Interest expense, net	$	(371)		$	(2,777)		$	2,406		(87)	%
Reorganization items, net	$	(42)		$	(2,988)		$	2,946		99	%
Loss on derivatives	$	(61,467)		$	(65,231)		$	3,764		6	%
Loss on change in fair value of warrants	$	(29,323)		$	(3,574)		$	(25,749)		NM
Loss on deconsolidation of Superior	$	(13,141)		$	—		$	(13,141)		—	%
Income tax benefit	$	—		$	—		$	—		—	%
Average interest rate on long-term debt outstanding	2.2		%	6.7		%	(4.5)		%	(68)	%
Average long-term debt outstanding	$	6,338		$	77,852		$	(71,514)		(92)	%

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

2.Mid-Stream activity and metrics shown in this table for the six months ended June 30, 2022 reflect Superior activity on a consolidated basis for the two months prior to March 1, 2022.

Table of Contents

Oil and Natural Gas

Oil and natural gas revenues increased ~~$63.9~~$73.7 million or ~~55% in~~64% during the first ~~nine~~six months of ~~2021~~2022 as compared to the first ~~nine~~six months of ~~2020~~2021 primarily due to higher commodity prices, partially offset by lower production volumes. Including derivatives settled, average oil prices increased 22% to $58.23 per barrel, average natural gas prices increased 32% to $3.78 per Mcf, and NGLs prices increased 88% to $33.82 per barrel. Oil production decreased 11%, natural gas production decreased 11%, and NGLs production decreased 5%. 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~~increased $15.3 million or ~~54%~~42% between the comparative first ~~nine~~six months of ~~2021~~2022 and ~~2020~~2021 primarily due to ~~the settlement of Predecessor Period liabilities subject to compromise under the Plan offset by~~ increased production ~~tax~~taxes on higher revenues, higher lease operating expenses, ~~due to increased revenues.~~and employee separation benefits.

Contract Drilling

Drilling revenues ~~decreased $25.0~~increased $28.8 million or ~~32% in~~85% during the first ~~nine~~six months of 2022 compared to the first six months of 2021 ~~versus the first nine months of 2020. The decrease was~~primarily 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~~an increase in the average number of ~~drilling~~ rigs in use ~~and a 5% decrease in~~from 9.7 during the first six months of 2021 to 15.9 during the first six months of 2022 as well as increases to the average ~~dayrate. Average drilling rig utilization decreased from 10.9 drilling~~dayrates on daywork contracts of 6% and 25% on BOSS rigs ~~in the first nine months of 2020 to 10.1 drilling~~and SCR rigs, ~~in the first nine months of 2021.~~respectively.

Drilling operating costs ~~decreased 13.5~~increased $26.0 million or ~~25%~~100% between the comparative first ~~nine~~six months of 2022 and 2021 ~~and 2020. The decrease was~~primarily due ~~primarily~~ to an increase in the ~~reduced~~average number of ~~drilling~~operating rigs ~~operating.~~as well as $6.6 million of transportation and start up costs associated with bringing stacked rigs back into service.

Mid-Stream

Our mid-stream revenues ~~increased $86.1~~decreased $42.7 million or ~~65% in~~34% during the first ~~nine~~six months of ~~2021~~2022 as compared to the first ~~nine~~six months of ~~2020~~2021 primarily due to ~~higher prices,~~the absence of activity subsequent to March 1, 2022 as a result of the deconsolidation of Superior, partially offset by ~~lower volumes.~~higher gas, NGL, and condensate prices as well as higher volumes during the consolidated period. 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~~increased 18% while gas gathered volumes per day ~~decreased 22%~~increased 18% between the comparative ~~periods also~~first six months of 2022 and 2021 primarily due to ~~declining volumes and fewer~~connecting new wells ~~connected to our~~as well as new volumes from the processing plant and gathering ~~systems. We also experienced overall lower volumes due to the February 2021 winter storm.~~system acquired in November 2021.

Operating costs ~~increased 88.4~~decreased $30.6 million or ~~95% in~~29% during the first ~~nine~~six months of ~~2021~~2022 compared to the first ~~nine~~six months of ~~2020~~2021 primarily due to the absence of activity subsequent to March 1, 2022 as a result of the deconsolidation of Superior, partially offset by higher gas, ~~NGLs,~~NGL, and condensate prices ~~partially offset by lower~~as well as higher purchase ~~volumes.~~volumes related to the processing plant and gathering system acquired in November 2021.

General and Administrative

Corporate general and administrative expenses ~~decreased $28.9~~increased $2.2 million or ~~65% in~~19% during the first ~~nine~~six months of ~~2021~~2022 as compared to the first ~~nine~~six months of ~~2020~~2021 primarily due to ~~reductions in payroll and benefits, the absence of~~employee separation ~~benefits recognized in the third quarter of 2020 as well as lower legal and office spend.~~benefits.

~~Other Income (Expense)~~Interest Expense, Net

Interest expense, net decreased ~~$19.8~~$2.4 million between the comparative first ~~nine~~six months of ~~2021~~2022 and ~~2020~~2021 primarily due to a ~~reduction~~92% decrease in average long-term debt outstanding ~~partially offset by~~and a ~~higher average interest rate. Our~~decrease in the average interest rate ~~increased~~ from ~~5.5% in~~6.7% during the first ~~nine months of 2020 to 6.7% in the first nine~~six months of 2021 ~~and our~~to 2.2% during the first six months of 2022. Our average debt outstanding decreased ~~$426.8~~$71.5 million induring the first ~~nine~~six months of ~~2021~~2022 compared to the first ~~nine~~six months of ~~2020~~2021 primarily due to ~~the Notes being settled with the Plan and~~ payments made under the Exit credit ~~agreement.~~

~~Write-off~~agreement and the deconsolidation of ~~Debt Issuance Costs~~

~~Due to~~Superior's outstanding long-term debt, partially offset by borrowings under the ~~termination of the remaining commitments of the Predecessor Period Unit~~Superior credit agreement ~~unamortized debt issuance costs of $2.4 million were written off during the first nine months of 2020.~~prior to deconsolidation.

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~~Gain (Loss) on Derivatives

~~Loss~~The $3.8 million favorable change in gain (loss) on derivatives ~~increased by $98.2 million~~between the comparative first six months of 2022 and 2021 is primarily due to ~~increases in forward prices used to estimate~~less unfavorable pricing changes on unsettled commodity derivative positions and new commodity derivative positions executed during the ~~fair value in mark-to-market accounting.~~second quarter of 2022, partially offset by higher settlement payments driven by higher average pricing.

Loss on Change in Fair Value of Warrants

~~Loss~~The $25.7 million unfavorable change in loss on change in fair value of warrants ~~increased by $12.6 million~~between the comparative second quarters of 2022 and 2021 is primarily due to changes in the underlying assumptions used to estimate the fair value, including ~~estimated strike price,~~ entity value, volatility, duration to exercise, and other inputs.

Loss on Deconsolidation of Superior

Loss on deconsolidation of $13.1 million during the first six months of 2022 represents the loss recognized on the March 1, 2022 deconsolidation of Superior.

Income Tax Benefit

We did not record an income tax benefit induring first six months of 2022 or during the first ~~nine~~six 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~~six months ~~2021~~of 2022 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~~$0.2 million per month ($~~3.0~~2.6 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~~1.4 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~~2.5 million annualized) change in our pre-tax operating cash flow.

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

~~At September~~Table of Contents

As of June 30, ~~2021, these~~2022, we had the following commodity derivatives ~~were~~ outstanding:

Term

Commodity

Contracted Volume

Weighted Average

Fixed Price for Swaps

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~~Jul'22 - Dec'22

Natural gas - swap

5,000 MMBtu/day

$2.61

IF - NYMEX (HH)

Jul'22 - Feb'23

Natural gas - swap

18,765 MMBtu/day

$9.14

IF - NYMEX (HH)

Jan'23 - Dec'23

Natural gas - swap

22,000 MMBtu/day

$2.46

IF - NYMEX (HH)

~~Jan'22~~Jul'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~~Jul'22 - Dec'22

Crude oil - swap

2,300 Bbl/day

$42.25

WTI - NYMEX

Jul'22 - Dec'22

Crude oil - swap

596 Bbl/day

$103.98

WTI - NYMEX

Jan'23 - Feb'23

Crude oil - swap

1,339 Bbl/day

$95.40

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~~as its borrowings carry variable interest rates. ~~A 1% increase in the interest rates on the~~We had no outstanding borrowings under ~~these facilities at September~~this facility as of June 30, ~~2021 would reduce our annual pre-tax cash flow by less than $0.1 million. For further information, see~~2022. See Note 9 – Long-Term Debt and Other Long-Term ~~Liabilities.~~Liabilities for more information on the Exit credit agreement.

~~Table of Contents~~

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~~internal control over financial reporting and make modifications as necessary; our intent in this regard is that the Disclosure Controls and ~~ICFR~~internal control over financial reporting 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~~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.

2022.

~~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.

~~Table of Contents~~

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~~internal control over financial reporting during the quarter ended ~~September~~June 30, ~~2021,~~2022, that materially affected, ~~our ICFR~~ or are reasonably likely to materially affect, ~~it, as defined in Rule 13a – 15(f) under the Exchange Act.~~our internal control over financial reporting.

5548

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For further information about the outstanding legal proceedings, please see Note 1516 – 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,~~2021, 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

OnIn June ~~16,~~ 2021, ~~the company~~we repurchased an aggregate of 600,000 shares of ~~its~~our 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~~our reorganization. The Lenders were paid $15.00 per share for their respective shares, for an aggregate cash purchase price of $9.0 million.

~~The 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.~~

~~Table of Contents~~

~~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.~~

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

The cumulative number of shares repurchased ~~under all methods since~~as of June 30, 2022 totaled 2,197,392. The cash purchase price and any direct acquisition costs are reflected as treasury stock on the ~~Effective Date~~unaudited condensed consolidated balance sheets as of June 30, 2022.

The table below shows share repurchase activity for the three months ended June 30, 2022:


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)
April 1, 2022 through April 30, 2022	—	$	—	—	$	8,570
May 1, 2022 through May 31, 2022	—	$	—	—	$	8,570
June 1, 2022 through June 30, 2022	247,429	$	53.63	247,429	$	45,300

1.Reflects the June 2022 increase to ~~1,739,963 shares.~~authorized repurchases from $50.0 million to $100.0 million.

Item 3. Defaults Upon Senior Securities

Not applicable.

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Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

~~Table of Contents~~

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).

5850

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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~~August 11, 2022	By: /s/ Philip B. Smith
		PHILIP B. SMITH
		President and Chief Executive Officer

Date:	~~November 12, 2021~~August 11, 2022	By: /s/ Thomas D. Sell
		THOMAS D. SELL
		Chief Financial Officer

5951


		Page Number
	PART I. Financial Information

Item 1.	Financial Statements (Unaudited)	4











	Notes to Unaudited Condensed Consolidated Financial Statements	1110

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	4135

Item 3.	Quantitative and Qualitative Disclosure s About Market Risk	5347

Item 4.	Controls and Procedures	5448

	PART II. Other Information

Item 1.	Legal Proceedings	5649

Item 1A.	Risk Factors	5649

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5649

Item 3.	Defaults Upo n Senior Securities	5749

Item 4.	Mine Safety Disclosures	5750

Item 5.	Other Information	5750

Item 6.	Exhibits	5850

Signatures		5951


	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)


	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


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


	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)


		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



	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)


	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


	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