UNIT CORP - Quarter Report: 2020 September (Form 10-Q)

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

[Commission File Number 1-9260]

UNIT CORPORATION

(Exact name of registrant as specified in its charter)


Delaware			73-1283193
(State or other jurisdiction of incorporation)			(I.R.S. Employer Identification No.)

8200 South Unit Drive,

Tulsa,

Oklahoma

74132

(Address of principal executive offices)

(Zip Code)

(918) 493-7700

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year,

if changed since last report)

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


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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ * No ☐

* Effective January 1, 2021, the registrant’s obligation to file reports under 15(d) of the Securities Exchange Act of 1934 was automatically suspended.

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

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

Smaller reporting company ☐ Emerging growth company ☐

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

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

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TABLE OF CONTENTS


		Page Number
	PART I. Financial Information

Item 1.	Financial Statements (Unaudited)	4











	Notes to Unaudited Condensed Consolidated Financial Statements	13

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

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	30

Item 4.	Controls and Procedures	31

	PART II. Other Information

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36

Item 3.	Defaults On Senior Securities	36

Item 4.	Mine Safety Disclosures	36

Item 5.	Other Information	36

Item 6.	Exhibits	36

Signatures		38

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Forward-Looking Statements

This report contains “forward-looking statements” – meaning, statements related to future events within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included or incorporated by reference in this document that addresses activities, events or developments we expect or anticipate will or may occur, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are used to identify forward-looking statements. This report modifies and supersedes documents filed by us before this report. In addition, certain information we file with the United States Securities Exchange Commission (SEC) will automatically update and supersede information in this report.

These forward-looking statements may include, among others, things such as:

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

•prices for oil, natural gas liquids (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 of the oil and natural gas industry;

•our business strategy;

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

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

•volumes and prices for natural gas gathered and processed;

•expansion and growth of our business and operations;

•demand for our drilling rigs and drilling rig rates;

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

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

•our ability to transport or convey our oil or natural gas production to established pipeline systems;

•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;

•our projected production guidelines;

•our anticipated capital budgets;

•our financial condition and liquidity;

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

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

•our plan to have the common stock of reorganized Unit Corporation quoted on one of the OTC markets.

These statements are based on assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and expected future developments, and other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to 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, including:

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

•general economic, market, or business conditions;

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

•demand for our land drilling services;

•changes in laws or regulations;

•changes in the current geopolitical situation;

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

•risks associated with future weather conditions;

•decreases or increases in commodity prices;

•the amount and terms of our debt;

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•future compliance with covenants under our debt agreements;

•inability to maintain relationship with suppliers, customers, employees and other third parties;

•ability to satisfy our short- or long-term liquidity needs, including ability to generate sufficient cash flow from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs;

•our ability to continue as a going concern;

•the public health crisis related to a novel strain of coronavirus (COVID-19) and resulting impact on demand for oil and natural gas;

•interruptions or cessation of our business operations as a result of the COVID-19 pandemic;

•other risks related to the outbreak of COVID-19 and its impact on our business, suppliers, customers, employees and supply chains;

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

•the risks associated with ineffective internal controls, which could impact the accuracy and timely reporting of our business and financial results; and

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

You should not place undue reliance on these forward-looking statements. Except as required by law, we disclaim any intention 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 unanticipated events.

To help provide you with a more thorough understanding of the possible effects of these influences on any forward-looking statements made by us, this discussion outlines some (but not all) of the factors that could cause our consolidated results to differ materially from those that may be presented in any forward-looking statement made by us or on our behalf.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	Successor		Predecessor
	September 30, 2020		December 31, 2019
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	29,784	$	571
Restricted cash (Note 3)	7,458		—
Accounts receivable, net of allowance for doubtful accounts of $3,783 and $2,332 at September 30, 2020 and December 31, 2019, respectively	52,824		82,656
Materials and supplies	—		449
Current derivative asset (Note 13)	2,367		633

Current income tax receivable	850		1,756
Assets held for sale (Note 6)	—		5,908
Prepaid expenses and other	12,531		13,078
Total current assets	105,814		105,051
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties	238,766		6,341,582
Unproved properties not being amortized	735		252,874
Drilling equipment	63,541		1,295,713
Gas gathering and processing equipment	250,608		824,699
Saltwater disposal systems	—		69,692
Land and building	32,635		59,080
Transportation equipment	3,291		29,723
Other	9,961		57,992
	599,537		8,931,355
Less accumulated depreciation, depletion, amortization, and impairment	20,907		6,978,669
Net property and equipment	578,630		1,952,686


Right of use asset (Note 15)	6,488		5,673
Other assets	17,628		26,642
Total assets (1)	$	708,560	$	2,090,052

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


	Successor		Predecessor
	September 30, 2020		December 31, 2019
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	37,307	$	84,481
Accrued liabilities (Note 8)	28,175		46,562
Current operating lease liability (Note 15)	3,985		3,430
Current portion of long-term debt (Note 9)	400		108,200
Current derivative liabilities (Note 13)	1,114		—
Warrant liability (Note 2)	885		—
Current portion of other long-term liabilities (Note 9)	12,324		17,376
Total current liabilities	84,190		260,049
Long-term debt less debt issuance costs (Note 9)	143,600		663,216
Non-current derivative liabilities (Note 13)	1,749		27
Operating lease liability (Note 15)	2,431		2,071
Other long-term liabilities (Note 9)	43,790		95,341
Deferred income taxes	—		13,713
Commitments and contingencies (Note 16)
Shareholders’ equity:
Predecessor preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued at December 31, 2019	—		—
Successor preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued at September 30, 2020	—		—
Predecessor common stock, $0.20 par value, 175,000,000 shares authorized, 55,443,393 shares issued as of December 31, 2019	—		10,591
Successor common stock, $0.01 par value, 25,000,000 shares authorized, 12,000,000 shares issued as of September 30, 2020	120		—
Predecessor capital in excess of par value	—		644,152
Successor capital in excess of par value	197,212		—

Retained earnings (deficit)	(8,968)		199,135
Total shareholders’ equity attributable to Unit Corporation	188,364		853,878
Non-controlling interests in consolidated subsidiaries	244,436		201,757
Total shareholders' equity	432,800		1,055,635
Total liabilities(1) and shareholders’ equity	$	708,560	$	2,090,052

_______________________

(1)Unit Corporation's consolidated total assets as of September 30, 2020 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $45.9 million and $257.0 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of September 30, 2020 include total current and long-term liabilities of the VIE of $26.5 million and $15.6 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, 2019 include total current and long-term assets of the VIE of $28.8 million and $434.3 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2019 include total current and long-term liabilities of the VIE of $32.2 million and $26.0 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 17 – Variable Interest Entity Arrangements.

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)


	Successor		Predecessor
	One Month Ended		Two Months Ended		Three Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	13,643	$	27,961	$	78,045
Contract drilling	4,414		7,685		37,596
Gas gathering and processing	14,789		29,928		39,798
Total revenues	32,846		65,574		155,439
Expenses:
Operating costs:
Oil and natural gas	6,674		15,488		35,364
Contract drilling	2,989		5,410		28,796
Gas gathering and processing	9,852		17,822		28,493
Total operating costs	19,515		38,720		92,653
Depreciation, depletion, and amortization	7,467		17,919		70,214
Impairments (Note 4)	13,237		16,572		234,880
Loss on abandonment of assets (Note 4)	—		1,179		—
General and administrative	1,582		5,399		10,094
(Gain) loss on disposition of assets	(222)		(1,356)		231
Total operating expenses	41,579		78,433		408,072
Loss from operations	(8,733)		(12,859)		(252,633)
Other income (expense):
Interest, net (excludes interest expense of $7.0 million on senior subordinated notes subject to compromise, for the two months ended August 31, 2020)	(826)		(1,959)		(9,534)
Gain (loss) on derivatives (Note 13)	3,939		(4,250)		4,237
Reorganization items, net (Note 3)	(1,155)		141,002		—
Other, net	39		1,931		(622)
Total other income (expense)	1,997		136,724		(5,919)
Income (loss) before income taxes	(6,736)		123,865		(258,552)
Income tax benefit:
Deferred	—		(4,750)		(50,763)
Total income taxes	—		(4,750)		(50,763)
Net income (loss)	(6,736)		128,615		(207,789)
Net income (loss) attributable to non-controlling interest	2,232		73,484		(903)
Net income (loss) attributable to Unit Corporation	$	(8,968)	$	55,131	$	(206,886)
Net income (loss) attributable to Unit Corporation per common share (Note 7):
Basic	$	(0.75)	$	1.03	$	(3.91)
Diluted	$	(0.75)	$	1.03	$	(3.91)

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) - CONTINUED


	Successor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	13,643	$	103,439	$	241,955
Contract drilling	4,414		73,519		131,788
Gas gathering and processing	14,789		99,999		136,533
Total revenues	32,846		276,957		510,276
Expenses:
Operating costs:
Oil and natural gas	6,674		117,691		104,320
Contract drilling	2,989		51,810		89,505
Gas gathering and processing	9,852		68,045		100,339
Total operating costs	19,515		237,546		294,164
Depreciation, depletion, and amortization	7,467		115,496		198,632
Impairments (Note 4)	13,237		867,814		234,880
Loss on abandonment of assets (Note 4)	—		18,733		—
General and administrative	1,582		42,766		29,899
(Gain) loss on disposition of assets	(222)		(89)		1,424
Total operating expenses	41,579		1,282,266		758,999
Loss from operations	(8,733)		(1,005,309)		(248,723)
Other income (expense):
Interest, net (excludes interest expense of $12.4 million on senior subordinated notes subject to compromise, for the eight months ended August 31, 2020)	(826)		(22,824)		(27,067)
Write-off of debt issuance costs (Note 9)	—		(2,426)		—
Gain (loss) on derivatives (Note 13)	3,939		(10,704)		5,232
Reorganization items, net (Note 3)	(1,155)		133,975		—
Other, net	39		2,034		(611)
Total other income (expense)	1,997		100,055		(22,446)
Loss before income taxes	(6,736)		(905,254)		(271,169)
Income tax benefit:
Current	—		(917)		—
Deferred	—		(13,713)		(53,081)
Total income taxes	—		(14,630)		(53,081)
Net loss	(6,736)		(890,624)		(218,088)
Net income attributable to non-controlling interest	2,232		40,388		811
Net loss attributable to Unit Corporation	$	(8,968)	$	(931,012)	$	(218,899)
Net loss attributable to Unit Corporation per common share (Note 7):
Basic	$	(0.75)	$	(17.45)	$	(4.14)
Diluted	$	(0.75)	$	(17.45)	$	(4.14)

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 COMPREHENSIVE INCOME (LOSS) (UNAUDITED)


	Successor		Predecessor
	One Month Ended		Two Months Ended		Three Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Net income (loss)	$	(6,736)	$	128,615	$	(207,789)
Other comprehensive loss, net of taxes:
Reclassification adjustment for write-down of securities, net of tax of $0, $0, and ($45)	—		—		487
Comprehensive income (loss)	(6,736)		128,615		(207,302)
Less: Comprehensive income (loss) attributable to non-controlling interest	2,232		73,484		(903)
Comprehensive income (loss) attributable to Unit Corporation	$	(8,968)	$	55,131	$	(206,399)


	Successor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Net loss	$	(6,736)	$	(890,624)	$	(218,088)
Other comprehensive loss, net of taxes:
Reclassification adjustment for write-down of securities, net of tax of $0, $0, and ($47)	—		—		481
Comprehensive loss	(6,736)		(890,624)		(217,607)
Less: Comprehensive income attributable to non-controlling interest	2,232		40,388		811
Comprehensive loss attributable to Unit Corporation	$	(8,968)	$	(931,012)	$	(218,418)

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		Capital in Excess of Par Value		Accumulated Other Comprehensive Income		Retained Earnings (Deficit)		Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, December 31, 2019 (Predecessor)	$	10,591	$	644,152	$	—	$	199,135	$	201,757	$	1,055,635
Net loss	—		—		—		(770,494)		(33,180)		(803,674)

Activity in employee compensation plans	103		2,391		—		—		31		2,525
Balances, March 31, 2020 (Predecessor)	10,694		646,543		—		(571,359)		168,608		254,486
Net income (loss)	—		—		—		(215,649)		84		(215,565)
Activity in employee 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 (loss)	—		—		—		55,131		73,484		128,615
Activity in employee 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 employee compensation plans	—		9		—		—		4		13
Balances, September 30, 2020 (Successor)	$	120	$	197,212	$	—	$	(8,968)	$	244,436	$	432,800

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	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Capital in Excess of Par Value		Accumulated Other Comprehensive Income		Retained Earnings (Deficit)		Non-controlling Interest in Consolidated Subsidiaries		Total
Balances, December 31, 2018 (Predecessor)	$	10,414	$	628,108	$	(481)	$	752,840	$	202,563	$	1,593,444
Cumulative effect adjustment for adoption of ASUs	—		—		—		174		—		174
Net income (loss)	—		—		—		(3,504)		1,222		(2,282)
Other comprehensive gain	—		—		24		—		—		24
Total comprehensive loss											(2,258)
Distributions to non-controlling interest	—		—		—		—		(918)		(918)
Activity in employee compensation plans	164		5,253		—		—		—		5,417
Balances, March 31, 2019 (Predecessor)	10,578		633,361		(457)		749,510		202,867		1,595,859
Net income (loss)	—		—		—		(8,509)		492		(8,017)
Other comprehensive loss	—		—		(30)		—		—		(30)
Total comprehensive loss											(8,047)
Activity in employee compensation plans	12		5,408		—		—		—		5,420
Balances, June 30, 2019 (Predecessor)	10,590		638,769		(487)		741,001		203,359		1,593,232
Net income (loss)	—		—		—		(206,886)		(903)		(207,789)
Reclassification adjustment for write-down of securities	—		—		487		—		—		487
Total comprehensive loss											(207,302)
Activity in employee compensation plans	—		5,273		—		—		30		5,303
Balances, September 30, 2019 (Predecessor)	$	10,590	$	644,042	$	—	$	534,115	$	202,486	$	1,391,233

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Successor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
OPERATING ACTIVITIES:
Net loss	$	(6,736)	$	(890,624)	$	(218,088)
Adjustment to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	7,467		115,496		198,632
Impairments (Note 4)	13,237		867,814		234,880
Loss on abandonment of assets (Note 4)	—		18,733		—
Amortization of debt issuance costs and debt discount	—		1,079		1,677
(Gain) loss on derivatives (Note 13)	(3,939)		10,704		(5,232)
Cash receipts (payments) on derivatives settled (Note 13)	(1,418)		(4,244)		11,829
Loss on disposition of assets	(222)		(89)		1,424
Write-off of debt issuance costs	—		2,426		—
Deferred tax benefit	—		(13,713)		(53,081)
Employee stock compensation plans	13		4,786		17,027
Bad debt expense	—		3,155		—
ARO liability accretion (Note 10)	116		1,545		1,770
Contract assets and liabilities, net (Note 5)	324		2,459		(1,930)
Noncash reorganization items	1,024		(138,797)		—
Other, net	(2,623)		12,164		562

Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(2,202)		28,880		38,821
Material and supplies	—		89		(51)
Prepaid expenses and other	194		(3,849)		(1,873)
Accounts payable	2,366		(18,381)		(31,606)
Accrued liabilities	2,082		44,811		17,086
Income taxes	—		906		—
Contract advances	(9)		(394)		7,603

Net cash provided by operating activities	9,674		44,956		219,450
INVESTING ACTIVITIES:
Capital expenditures	(1,598)		(25,775)		(364,954)
Producing properties and other acquisitions	—		(382)		(3,345)
Proceeds from disposition of property and equipment	576		6,018		10,506


Net cash used in investing activities	(1,022)		(20,139)		(357,793)
FINANCING ACTIVITIES:
Borrowings under line of credit, including borrowings under DIP credit facility	—		87,400		392,200
Payments under line of credit	(4,000)		(64,100)		(254,000)

DIP financing costs	—		(990)		—
Exit facility financing costs	—		(3,225)		—
Net payments on finance leases	(350)		(2,757)		(2,984)
Employee taxes paid by withholding shares	—		(43)		(4,080)




Distributions to non-controlling interests	—		—		(918)

Bank overdrafts	—		(8,733)		2,285
Net cash provided by (used in) financing activities	(4,350)		7,552		132,503
Net increase (decrease) in cash and cash equivalents	4,302		32,369		(5,840)
Cash, restricted cash, and cash equivalents, beginning of year	32,940		571		6,452
Cash, restricted cash, and cash equivalents, end of year	$	37,242	$	32,940	$	612

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - CONTINUED


	Successor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)	$	251	$	6,417	$	13,686
Income taxes	—		—		—
Reorganization items	131		4,822		—

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(128)		8,561		40,210
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	(215)		29,189		1,906
Non-cash trade of property, plant, and equipment	—		1,403		—

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PREPARATION AND PRESENTATION

The unaudited condensed consolidated financial statements in this report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires. We consolidate the activities of Superior Pipeline Company, L.L.C. (Superior), a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, (SP Investor) which qualifies as a Variable Interest Entity (VIE) under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power to direct those activities that most significantly affect the economic performance of Superior as further described in Note 17 – Variable Interest Entity Arrangements. Intercompany balances and transactions have been eliminated. 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 condensed consolidated financial statements are unaudited and under the rules and regulations of the SEC do not include all the notes in our annual financial statements. This report should be read along with the audited consolidated financial statements and notes in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on March 16, 2020. In the opinion of our management, the unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) and are fairly stated. Operating results for the eight months ended August 31, 2020 (Predecessor) and one month ended September 30, 2020 (Successor), are not necessarily indicative of the results that may be expected for the period from the Effective Date to December 31, 2020 (Successor). Certain amounts in this report for prior periods have been reclassified to conform to current year presentation. The reclassification had no impact to consolidated net income (loss) or shareholders' equity.

Comparability of Financial Statements to Prior Periods

As discussed in further detail in Note 3 – Fresh Start Accounting, the following unaudited condensed consolidated financial statements have been prepared in accordance with Financial Accounting Standard Board (FASB) ASC Topic 852, Reorganizations. 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 condensed consolidated financial statements. This was reflected in our condensed consolidated balance sheet as of September 1, 2020. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 1, 2020, are not comparable to the Condensed Consolidated Financial Statements and Notes before that date. To facilitate the financial statement presentations, we refer to the reorganized company in these unaudited condensed consolidated financial statements and notes as the "Successor" for periods subsequent to August 31, 2020, and "Predecessor" for periods prior to September 1, 2020. Furthermore, the unaudited condensed consolidated financial statements and notes have been presented with a "black line" division to delineate the lack of comparability between the Predecessor and Successor.

We have applied the relevant guidance provided in U.S. GAAP regarding the accounting and financial statement disclosures for entities that have filed petitions with the bankruptcy court and reorganized as going concerns in preparing the condensed consolidated financial statements and notes through the period ended August 31, 2020, or Predecessor periods. That guidance requires, for periods after our bankruptcy filing on May 22, 2020, or post-petition periods, certain transactions and events that were directly related to our reorganization be distinguished from our normal business operations. Accordingly, certain expenses, realized gains, and losses and provisions that were realized or incurred in the bankruptcy proceedings have been included in "Reorganization items, net" on our condensed Consolidated Statements of Operations. In addition, certain liabilities and other obligations incurred before May 22, 2020, or pre-petition periods, have been classified as "Liabilities subject to compromise" on our Predecessor Condensed Consolidated Balance Sheet through August 31, 2020. See Note 3 – Fresh Start Accounting for further detail.

Changes in Accounting Policies

Upon emergence from bankruptcy, the company elected to change the accounting policies related to depreciation of fixed assets of our Contract Drilling segment and the allocation of earnings and losses between Unit and its partners in Superior.

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Depreciation

Prior to emergence from bankruptcy, the company recorded depreciation of drilling equipment using the units-of-production method based on estimated useful lives starting at 15 years, including a minimum provision of 20% of the active rate when the equipment was idle, except when idle for greater than 48 months, then it was depreciated at the full active rate. The company also utilized the composite method of depreciation for drill pipe and collars to calculate the depreciation by footage actually drilled compared to total estimated remaining footage. As of emergence, the company elected to depreciate all drilling assets utilizing the straight-line method over the useful lives of the assets ranging from four to ten years.

Earnings/Losses Allocation

Historically, the company allocated earnings and losses between Unit and the partners in Superior based on the ownership percentage (50/50) of the joint venture. Upon emergence, the company elected to allocate earnings and losses using the Hypothetical Liquidation at Book Value (HLBV) method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if Superior were liquidated at book value at the end of each measurement period. For additional information on the allocation of earnings, see Note 17 – Variable Interest Entity Arrangements.

NOTE 2 – EMERGENCE FROM VOLUNTARY REORGANIZATION UNDER CHAPTER 11

Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On May 22, 2020 (Petition Date), Unit together with its wholly owned subsidiaries, Unit Drilling Company (UDC); Unit Petroleum Company (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). During the pendency of the Chapter 11 Cases, the Debtors operated their business as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and under the provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

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.

Following emergence, the company implemented the provisions of the Plan as follows:

•Each lender under the (i) the Senior Credit Agreement dated as of September 13, 2011 (as amended, the Unit credit agreement, and the loan facility, the Unit credit facility), by and among the company, UPC and UDC, as borrowers, the lenders party thereto and BOKF, NA dba Bank of Oklahoma, as administrative agent and (ii) the $36.0 million multi-draw loan facility (DIP credit facility) under the Superpriority Senior Secured Debtor-in-Possession Credit Agreement dated May 27, 2020 (DIP credit agreement), by and among the Debtors, the RBL Lenders (in such capacity, the DIP Lenders) and BOKF, NA dba Bank of Oklahoma, as administrative agent received its pro rata share of revolving loans, term loans and letter of credit participations under the exit facility described below, in exchange for the lender’s allowed claims under the Unit credit facility or DIP credit facility;

•Each lender under the Unit credit facility and the DIP credit facility received (or will receive promptly after providing the company with its brokerage account information) its pro rata share of an equity fee under the exit facility equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and upon exercise of the warrants described below);

•The company issued a total of 12.0 million common shares of the reorganized Unit (New Common Stock) at a par value of $0.01 per share to be subsequently distributed in accordance with the Plan;

•Each holder of 6.625% senior subordinated notes due 2021 (Notes) received its pro rata share of New Common Stock based on equity allocations at each of Unit, UDC and UPC in exchange for the holder’s allowed Notes claim;

•Each holder of an allowed general unsecured claim against Unit or UPC is entitled to receive its pro rata share of New Common Stock based on equity allocations at each of Unit and UPC, respectively;

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•A disputed claims reserve was established for distribution of New Common Stock on allowance of certain disputed general unsecured claims;

•Each holder of an allowed general unsecured claim against UDC, 8200 Unit, Unit Drilling Colombia and Unit Drilling USA received payment or will receive in full of that claim in the ordinary course of business; and

•Each retained or former employee with a claim for vested severance benefits, who opted in to a settlement, received or will receive cash payment(s) for the claim in lieu of an allocation of New Common Stock otherwise provided to holders of general unsecured claims.

On December 11, 2020, approximately 10.5 million shares of New Common Stock were distributed to the holders of the Notes who were entitled to receive their pro rata share of New Common Stock based on equity allocations at each of Unit, UDC, and UPC in exchange for the holder’s allowed Notes claim. The remaining 1.5 million shares are being held for the Disputed Claims Reserve.

All shares of New Common Stock are subject to the transfer restrictions in Article XIV of the company’s Amended and Restated Certificate of Incorporation (Charter). Article XIV of the Charter provides that, subject to the exceptions provided in Article XIV, any attempted transfer of the New Common Stock will be prohibited and void ab initio if (i) because of the transfer, any person becomes a Substantial Stockholder (as defined below) other than by reason of Treasury Regulations section 1.382-2T(j)(3) or (ii) the Percentage Stock Ownership (as defined in the Charter) interest of any Substantial Stockholder will be increased. A “Substantial Stockholder” means a person with a Percentage Stock Ownership of 4.75% or more.

Warrants

Each holder of the company’s common stock outstanding before the Effective Date (Predecessor Common Stock) that did not opt out of the release under the Plan, is entitled to receive its pro rata share of seven-year warrants (Warrants) to purchase an aggregate of 12.5% of the shares of New Common Stock, at an aggregate exercise price equal to the $650.0 million principal amount of the Notes plus interest thereon to the May 15, 2021 maturity date of the Notes. On the Effective Date, the company entered into a Warrant Agreement (Warrant Agreement) with American Stock Transfer & Trust Company, LLC. The Warrants will expire on the earliest of (i) September 3, 2027, (ii) the consummation of a Cash Sale (as defined in the Warrant Agreement) or (iii) the consummation of a liquidation, dissolutions or winding up of the company (such earliest date, the Expiration Date). Each Warrant that is not exercised on or before the Expiration Date will expire, and all rights under such Warrant and the Warrant Agreement will cease on the Expiration Date. On December 21, 2020, the company issued approximately 1.8 million Warrants to the holders of the Predecessor Common Stock that did not opt out of the releases under the Plan and owned their shares of Predecessor Common Stock in street name through the facilities of the DTC. The company expects to issue approximately 79,000 more Warrants to the holders of the Predecessor Common Stock that did not opt out of the releases under the Plan and owned their shares through direct registration with the company’s transfer agent (Direct Registration). Under the Plan, additional Warrants will be issued in book-entry form through the facilities of the DTC, and each holder owning shares of Predecessor Common Stock through Direct Registration must provide that holder’s brokerage account information to the company to receive holder’s distribution of Warrants. Any distribution not made will be deemed forfeited at the first anniversary of the Effective Date.

The Warrants are currently accounted for as a derivative liability as they are not indexed to the New Common Stock until all outstanding claims have been satisfied and the strike price for the Warrants can be determined. Accordingly, the Warrants are recorded at their fair value upon emergence utilizing the Black-Scholes-Merton option model. The inputs to the model require judgement, including estimating the strike price, expected term and the associated volatility. At emergence, the Warrants have a fair value of $0.9 million and will continue to be adjusted to fair value at each reporting period until determined to be an equity instrument, at which time they will be reported as Shareholders' equity and no longer be subject to future fair value adjustment. The Warrants are considered Level 3 fair value measurements under ASC 820, Fair Value Measurement.

Events of Default

The commencement of the Chapter 11 Cases constituted an event of default that accelerated the company's obligations under the Unit credit agreement and the indenture governing the Notes. Additionally, other events of default, including cross-defaults, existed or occurred under these debt agreements. The amounts owed in respect of the Notes were classified as liabilities subject to compromise. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the company. Superior and its subsidiaries were not debtors in the Chapter 11 Cases, and the Chapter 11 Cases did not result in an event of default under the Superior credit agreement. In addition, the Debtors' filing of the

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Bankruptcy Petitions constituted a termination event under their hedge agreements, which allowed the counterparties to those hedge agreements to terminate the outstanding hedges, and those termination events were not stayed by the Chapter 11 Cases.

On the Petition Date, the Debtors entered into a Continuation Agreement (Continuation Agreement) with Superior, SPC Midstream Operating, L.L.C., and SP Investor to continue the parties' contractual relationships during the course of the Chapter 11 Cases under the governance, operational, and related agreements entered into by those parties in connection with the formation of Superior (the company’s midstream joint venture with SP Investor), which agreements contained certain provisions that otherwise would have been triggered by the filing of the Chapter 11 Cases.

Liquidity, Unit Credit Facility, and Debtor-in-Possession Credit Agreement

To provide liquidity to fund our operations and the Chapter 11 Cases, the Debtors entered into the DIP credit agreement. Before repayment and termination on the Effective Date, borrowings under the DIP credit facility would have matured on the earliest of (i) September 22, 2020 (subject to a two-month extension to be approved by the DIP Lenders), (ii) the sale of all or substantially all of the assets of the Debtors under Section 363 of the Bankruptcy Code or otherwise, (iii) the effective date of a plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an order by the Bankruptcy Court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code, and (v) the date of termination of the DIP Lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP credit agreement and subject to the Bankruptcy Court’s orders.

On the Effective Date, the DIP credit agreement was paid in full and terminated. Following the Debtors’ emergence from the Chapter 11 Cases, each holder of an allowed claim under the DIP credit facility received its pro rata share of revolving loans, term loans, and letter-of-credit participations under the exit facility (as defined below). In addition, each holder was issued its pro rata share of an equity fee under the exit facility equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and on exercise of the Warrants).

Going Concern

At June 30, 2020, the significant risks and uncertainties related to the company’s liquidity and Chapter 11 Cases raised substantial doubt about the company’s ability to continue as a going concern. The company, therefore, concluded as of that date there was substantial doubt about the company’s ability to continue as a going concern. The company has since implemented changes that (i) minimize capital expenditures, (ii) aggressively manage working capital, and (iii) reduce recurring operating expenses. With the successful reorganization of our capital structure, in addition to these actions, there is no longer substantial doubt about the company's ability to continue as a going concern.

Exit Credit Agreement

On the Effective Date, under the terms of the Plan, the company entered into an amended and restated credit agreement (Exit credit agreement). Refer to Note 9 – Long-Term Debt and Other Long-Term Liabilities for the terms of the Exit credit agreement.

Interest Expense

The Debtors discontinued recording interest on liabilities subject to compromise as of the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the condensed consolidated statements of operations for the two and eight months ended August 31, 2020 was approximately $7.0 million and $12.4 million, respectively, representing interest expense from the Petition Date through August 31, 2020. In addition, the Debtors did not make the required interest payment on the Notes of $21.5 million on May 15, 2020.

NOTE 3 – FRESH START ACCOUNTING

On the Effective Date, the company qualified for and adopted fresh start accounting in accordance with the provisions set forth in FASB Topic ASC 852, Reorganizations, as (i) the Reorganization Value of the company’s assets immediately before the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor received less than 50% of the voting shares of the Successor. Refer to Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 for the terms of the Plan.

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Reorganization Value

Reorganization value, as determined in accordance with ASC 820, Fair Value Measurement, represents the fair value of the Successor's total assets before the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value was derived from the Successor's enterprise value, which represents the estimated fair value of an entity’s long-term debt and equity. The Successor’s enterprise value, confirmed by the Bankruptcy Court, was estimated to be within a range of $270.0 million to $380.0 million, with a midpoint of $325.0 million. Based on the various estimates and assumptions necessary for fresh start accounting, as further discussed below, the estimated enterprise value was determined to be $317.0 million before consideration of cash and cash equivalents, restricted cash and outstanding debt at the Effective Date. As a result, the reorganization value was determined to be $726.3 million at the Effective Date, as reconciled below.

The company estimated the enterprise value of the Successor using three valuation methods: net asset value (NAV), comparable public company analysis, and discounted cash flow (DCF). The NAV is a looking forward methodology under which future cash flows are discounted using various discount rates depending on reserve category. Similarly, DCF projects future cash flows which are discounted at rates above and below the company’s estimated weighted average cost of capital. The comparable public company analysis is based on the enterprise values of selected public companies with operating and financial characteristics comparable to the company. Under this methodology, certain financial multiples that measure financial performance and value are calculated for each selected company and then applied to imply an estimated enterprise value of the company.

The following table reconciles the enterprise value to the estimated fair value of the Successor's equity at the Effective Date (in thousands):


Enterprise value	$	559,205
Less: Fair value of noncontrolling interest	(242,200)
Enterprise value of Unit interests	317,005
Plus: Cash and cash equivalents	25,482
Plus: Restricted cash	7,458
Less: Fair value of capital leases	(4,622)
Less: Fair value of debt (including the fair value of current debt)	(148,000)
Fair value of Successor equity	$	197,323

The following table reconciles the enterprise value to the reorganization value of the Successor’s assets as of the Effective Date (in thousands):


Enterprise value	$	559,205
Plus: Cash and cash equivalents	25,482
Plus: Restricted cash	7,458
Plus: Current liabilities (excluding the fair value of capital leases and current debt)	86,897
Plus: Long-term asset retirement obligation	22,415
Plus: Other long-term liabilities (excluding long-term asset retirement obligation)	24,886
Reorganization value of Successor assets	$	726,343

Although the company believes the assumptions and estimates used to develop Enterprise Value and Reorganization Value were reasonable and appropriate, different assumptions and estimates would materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require significant judgment.

Valuation Process

Oil and Natural Gas Properties

Our oil and natural gas properties are accounted for under the full cost accounting method. The company determined the fair value of its oil and gas properties based on the anticipated cash flows associated with proved reserves and discounted using a weighted average cost of capital rate of 13.5%. The discount rate is commonly based on empirical studies of investment rates

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of return of publicly traded equity securities with investment return and risk characteristics similar to the subject company, which is consistent with a market-based approach. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $48.98 per barrel of oil, $2.68 per million cubic feet of natural gas and $18.51 per barrel of oil equivalent of natural gas liquids. Base pricing was derived from an average of forward strip prices. The company’s unproved acreage was determined to have no value due to capital constraints of our debt agreement and no plans to drill in our proved reserves cash flows. The company's salt water disposal assets were included in the cash flows of the proved reserves forecast, therefore, these values are included in the total value of our proved properties.

Drilling Equipment

The value of drilling rigs in operations (approximately $37.0 million) was estimated using an income-based approach utilizing discounted free cash flows over the remaining useful lives of the related assets. Anticipated cash flows associated with operating drilling rigs were discounted using a weighted average cost of capital rate of 13.8% for five years with a terminal value at the conclusion of the forecast period.

The fair value of rigs not in operation, and other related drilling equipment (approximately $26.5 million), was valued utilizing a market-based approach with varying ranges of economic obsolescence rates to adjust for the impact of the oil and gas downturn.

Land and Building

Our headquarters in Tulsa, OK was completed in September 2014 and resides on approximately 30 acres. To determine its fair value, the company utilized a market-based approach based on comparable tenant rates in our area.

Gas Gathering and Processing Equipment, Transportation Equipment, and Other Property

Gas gathering and processing equipment, transportation equipment and other was valued utilizing a market-based approach estimating what a market participant would pay for similar equipment in an orderly transaction. We utilized varying ranges of economic obsolescence rates depending on the underlying asset group. For pipelines and right-of-ways, we used a value per acre based on the location of the asset and estimated an average value of $129 per rod. We then applied an economic obsolescence rate of approximately 64% to determine the ultimate fair value.

Condensed Consolidated Balance Sheet

The adjustments included in the following condensed consolidated balance sheet reflect the effect of the transactions contemplated by the Plan (reflected in the column "Reorganization Adjustments") as well as fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column "Fresh Start Adjustments"). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions.

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	As of September 1, 2020
	Predecessor		Reorganization Adjustments (1)			Fresh Start Adjustments (11)			Successor
ASSETS	(In thousands)
Current assets:
Cash and cash equivalents	$	32,280	$	(6,798)	(2)	$	—		$	25,482
Restricted cash	—		7,458		(3)	—			7,458
Accounts receivable, net	50,621		—			—			50,621
Materials and supplies	64		—			(64)		(12)	—
Current income tax receivable	850		—			—			850
Prepaid expenses and other	13,692		6,382		(4)	(990)		(13)	19,084
Total current assets	97,507		7,042			(1,054)			103,495
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties	6,539,816		—			(6,301,532)		(14)	238,284
Unproved properties not being amortized	30,205		—			(30,205)		(14)	—
Drilling equipment	1,285,024		—			(1,221,566)		(15)	63,458
Gas gathering and processing equipment	833,788		—			(583,690)		(15)	250,098
Saltwater disposal systems	43,541		—			(43,541)		(15)	—
Land and building	59,080		—			(26,445)		(15)	32,635
Transportation equipment	15,577		—			(12,263)		(15)	3,314
Other	57,427		—			(47,469)		(15)	9,958
	8,864,458		—			(8,266,711)			597,747
Less accumulated depreciation, depletion, amortization, and impairment	7,923,868		—			(7,923,868)		(14) (15)	—
Net property and equipment	940,590		—			(342,843)			597,747
Right of use asset	7,476		—			(659)		(16)	6,817
Other assets	24,666		(6,382)		(4)	—			18,284
Total assets	$	1,070,239	$	660		$	(344,556)		$	726,343

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	As of September 1, 2020
	Predecessor		Reorganization Adjustments (1)			Fresh Start Adjustments (11)			Successor
LIABILITIES AND SHAREHOLDERS’ EQUITY	(In thousands)
Current liabilities:
Accounts payable	$	27,354	$	6,382	(4)	$	—		$	33,736
Accrued liabilities	36,990		(4,115)		(5)	—			32,875
Current operating lease liability	4,643		—			(669)		(16)	3,974
Current portion of long-term debt	124,000		(123,600)		(6)	—			400
Current derivative liabilities	5,089		—			—			5,089
Warrant liability	—		—			885		(17)	885
Current portion of other long-term liabilities	11,201		3,743		(7)	16		(18)	14,960
Total current liabilities	209,277		(117,590)			232			91,919
Long-term debt	16,000		131,600		(6)	—			147,600
Non-current derivative liabilities	766		—			—			766
Operating lease liability	2,760		—			11		(16)	2,771
Other long-term liabilities	61,393		(3,220)		(4) (7)	(14,409)		(18)	43,764
Liabilities subject to compromise	762,215		(762,215)		(8)	—			—
Deferred income taxes	4,466		—			(4,466)		(19)	—
Commitments and contingencies
Shareholders’ equity:
Predecessor preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued at December 31, 2019	—		—			—			—
Predecessor common stock, $0.20 par value, 175,000,000 shares authorized, 55,443,393 shares issued as of December 31, 2019	10,704		(10,704)		(9)	—			—
Predecessor capital in excess of par value	650,153		(650,153)		(9)	—			—
Successor preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued at September 1, 2020	—		—			—			—
Successor common stock, $0.01 par value, 25,000,000 authorized, 12,000,000 issued at September 1, 2020	—		120		(8)	—			120
Successor capital in excess of par value	—		197,203		(8)	—			197,203
Retained earnings (deficit)	(818,679)		1,215,619		(10)	(396,940)		(20)	—
Total shareholders’ equity attributable to Unit Corporation	(157,822)		752,085			(396,940)			197,323
Non-controlling interests in consolidated subsidiaries	171,184		—			71,016		(21)	242,200
Total shareholders' equity	13,362		752,085			(325,924)			439,523
Total liabilities and shareholders’ equity	$	1,070,239	$	660		$	(344,556)		$	726,343

Reorganization Adjustments

(1)Reflects accounts recorded as of the Effective Date, including among other items, settlement of the Predecessor's liabilities subject to compromise, cancellation of the Predecessor's equity, issuance of the New Common Stock and the Warrants, repayment of certain of Predecessor's liabilities and settlement with holders of the Notes.

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(2)The table below details the company’s uses of cash, under the terms of the Plan described in Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 (in thousands):


Funding of the professional fees escrow account	$	(7,458)
Proceeds from Exit credit facility	8,000
Payment of debt issuance costs on the Exit credit facility	(3,225)
Payment of professional fees	(3,943)
Payment of accrued interest payable under the Predecessor credit facility	(172)
Changes in cash and cash equivalents	$	(6,798)

(3)Represents the reserve for Professional Fee Escrow of $7.5 million.

(4)Represents the reclassification of other long-term assets related to deferred compensation to prepaid expenses and other assets as the deferred compensation payout is required to be paid within 12 months from the date of emergence in accordance with the Plan. Simultaneously, the current portion of deferred compensation liability was reclassified from other long-term liabilities to accounts payable.

(5)Represents the payment of the DIP Facility interest of $0.2 million and professional fees for $3.9 million.

(6)Represents the transition of the DIP credit agreement and the Predecessor credit agreement of $124.0 million into the Exit Facility and the issuance of an additional $8.0 million under the Exit Facility.

(7)Represents the reclassification of the short-term portion of the separation benefit liabilities from non-current to current liabilities which was offset by the increase in non-current portion of liabilities.

(8)Settlement of liabilities subject to compromise and the resulting net gain were determined as follows (in thousands):


Liabilities subject to compromise before the Effective Date:
6.625% senior subordinated notes due 2021 (including accrued interest as of the Petition Date)	$	672,369
Accounts payable	1,179
Employee separation benefit plan obligations	23,394
Litigation settlements	45,000
Royalty suspense accounts payable	20,273
Total liabilities subject to compromise	762,215
Separation settlement treatment	(6,905)
Successor Common Stock and APIC(1) issued to allowed claim holders	(175,521)
Successor Common Stock and APIC for disputed claims reserve	(11,936)
Gain on settlement of liabilities subject to compromise	$	567,853

(1) Balance excludes the Successor Common Stock and APIC of $9.9 million to the 5% Equity Facility which was not a liability subject to compromise.

(9)Represents the cancellation of Predecessor Common Stock.

(10)Represents the cumulative impact to Predecessor retained earnings of the reorganization adjustments described above.

Fresh Start Adjustments

(11)Reflects accounts recorded as of the Effective Date for the fresh start adjustments based on the methodologies noted below.

(12)Represents the reclassification of materials and supplies to proved properties.

(13)Represents the write off of the Predecessor's unamortized debt fees related to the DIP Facility.

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(14)Reflects a decrease of oil and natural gas properties, net, based on the methodology discussed above, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date:


	Successor		Predecessor
	Fair Value		Historical Book Value
	(In thousands)
Proved properties	$	238,284	$	6,539,816
Unproved properties	—		30,205
	238,284		6,570,021
Less accumulated depletion, amortization, and impairment	—		(6,305,113)
	$	238,284	$	264,908

(15)Reflects a decrease in fair value of drilling equipment, gas gathering and processing equipment, saltwater disposal systems, land and building, transportation equipment and other property and equipment and the elimination of accumulated depreciation, based upon the methodologies discussed above. The following table summarizes the components of other property and equipment as of the Effective Date:


	Successor		Predecessor
	Fair Value		Historical Book Value
	(In thousands)
Drilling equipment	$	63,458	$	1,285,024
Gas gathering and processing equipment	250,098		833,788
Saltwater disposal systems	—		43,541
Land and building	32,635		59,080
Transportation equipment	3,314		15,577
Other	9,958		57,427
	359,463		2,294,437
Less accumulated depreciation and impairment	—		(1,618,754)
	$	359,463	$	675,683

(16)Reflects the valuation adjustments to the company’s ROU assets, current operating lease liability, and operating lease liability, adjusted for fair value of favorable and unfavorable lease terms, and the revised incremental borrowing rates of the Successor.

(17)Represents the liability for the warrants estimated using a Black-Scholes-Merton model which utilizes various market-based inputs including: stock prices, strike price, time to maturity, risk-free rate, annual volatility rate, and annual dividend yield.

(18)Represents the reclassification of the short-term portion of Asset Retirement Obligation from non-current liabilities to current as well as the fair value adjustment, which was determined using our fresh start updates to these obligations, including the application of the Successor's credit adjusted risk free rate, which now incorporates a term structure based on the estimated timing of well plugging activity, and resetting all Asset Retirement Obligations to a single layer.

(19)Represents the adjustments to deferred tax liability as a result of the cumulative tax impact of the fresh start adjustments.

The significant revisions to the carrying value of our assets and liabilities as a result of applying fresh start accounting has resulted in the company increasing its overall net deferred tax asset position upon emergence from bankruptcy. In addition to the changes in book value, the company has approximately $726.4 million of net operating losses (NOLs) carried forward to offset taxable income in future years as of the Effective Date of emergence. Approximately $584.2 million of this NOL will expire commencing in fiscal 2021 through 2037. The NOLs of approximately

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$142.2 million from years ended subsequent to December 31, 2017 have an indefinite carryforward period. The amount of these NOLs which is actually available to offset future income may be severely limited due to change-in-control tax provisions.

Due to our history of operating losses and the uncertainty surrounding the realization of the deferred tax assets in future years, our management has determined that it is more likely than not that the deferred tax assets will not be realized in future periods. Accordingly, the company has recorded a 100% valuation allowance against its net deferred tax assets.

Our blended effective tax rate was 1.62% for the Predecessor period ending August 31, 2020 and 0.00% for the Successor period ending September 30, 2020 compared to 19.57% for the first nine months of 2019. The rate change was primarily due to the increase in the valuation allowance against our income tax benefit.

(20)Represents the cumulative impact of the fresh-start accounting adjustments discussed above.

(21)The valuation of the non-controlling interest was calculated by taking an income-based approach in valuing Superior as a whole. The value of the non-controlling interest was then determined based on a market-based approach for similar type investments, given the contractual rights of the related parties.

Reorganization Items. As described above in Note 1 – Basis Of Preparation And Presentation, our Condensed Consolidated Statements of Operations of the periods ended August 31, 2020 include "Reorganization items, net," which reflects gains recognized on the settlement of liabilities subject to compromise and costs and other expenses associated with the Chapter 11 proceedings, primarily professional fees, and the costs associated with the DIP facility. These post-petition costs for professional fees, as well as administrative fees charged by the U.S. trustee, have been reported in "Reorganization items, net" in our Condensed Consolidated Statement of Operations as described above. Similar costs were incurred during the pre-petition period have been reported in "General and administrative" expenses.

The following table summarizes the components included in "Reorganization items, net" in our Condensed Consolidated Statements of Operations for the periods presented:


	Successor		Predecessor
	One Month Ended		Two Months Ended		Eight Months Ended
	September 30, 2020		August 31, 2020
	(In thousands)
Gains on settlement of liabilities subject to compromise	$	—	$	(567,853)	$	(567,853)
Fresh start accounting adjustments	—		401,406		401,406
Legal and professional fees and expenses	1,155		10,923		15,745
Acceleration of Predecessor stock compensation expense	—		1,431		1,431
Exit Facility fees	—		3,225		3,225
5% equity facility	—		9,866		9,866
Adjustment to unamortized debt issuance costs associated with the 6.625% senior subordinated notes due 2021	—		—		2,205
Total reorganization items, net	$	1,155	$	(141,002)	$	(133,975)

NOTE 4 – IMPAIRMENTS

Successor

As of September 1, 2020, we adopted fresh start accounting and adjusted our assets to fair value. Under full cost accounting rules we must review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is called the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the most recent historical 12-month average price of our oil, NGLs, and natural gas), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties in the costs being amortized, less related income taxes. If the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in

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the period during which the excess occurs, even if prices are depressed for only a short while. Once incurred, a write-down of oil and natural gas properties is not reversible.

Although under fresh start accounting we recorded our assets at fair value on emergence, the application of the full cost accounting rules resulted in a non-cash ceiling impairment of $13.2 million pre-tax as of September 30, 2020, primarily due to the use of average 12-month historical commodity prices for the ceiling test versus forward prices for our fresh start fair value estimates.

We also anticipate a non-cash ceiling write-down in the fourth quarter of 2020 of our proved reserves, again due to the use of historical 12-month average commodity prices for the ceiling test. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at September 30, 2020, and only adjust the 12-month average price as of December 2020, our forward looking expectation is that we would recognize an impairment in the range of $30 million to $35 million pre-tax in the fourth quarter of 2020. Given the uncertainty associated with the factors used in calculating our estimate of our future period ceiling test write-down, these estimates should not necessarily be construed as indicative of our future development plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination.

There were no other impairment triggering events identified in the one month ended September 30, 2020 for any of our other asset groups.

Predecessor

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.

During the first quarter of 2020, global commodity prices declined due to factors that significantly impacted both demand and supply. As the COVID-19 pandemic spread, causing travel and other restrictions to be implemented globally, the demand for crude oil declined. Additionally, the supply shock late in the first quarter of 2020 from certain major oil producing nations increasing production further contributed to the sharp drop in crude oil prices. The sharp drop in crude oil prices resulted in prompt reactions from a number of domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production.

The above circumstances caused a triggering event that required our long-lived assets to be evaluated for impairment. At March 31, 2020, we determined that indicators of impairment existed for certain asset groups within our operating segments. For each asset group for which undiscounted future net cash flows could not recover the net book value, fair value was determined using discounted estimated cash flows to measure the impairment loss.

The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and estimated drilling rig utilization. Other key assumptions include volume projections, operating costs, timing of incurring those costs and using an appropriate discount rate. These key assumptions could change in the future and could result in additional impairment expense recorded on these asset groups. We believe our estimates and models used to determine fair value are similar to what a market participant would use and are appropriate under the circumstances. But given the rate of change impacting the energy industry, it is reasonably possible that these estimates and models may change in the near term potentially resulting in material impairment expense in the future interim periods.

The fair value measurement of our long-lived assets was based, in part, on significant inputs not observable in the market (as discussed above) and thus represents a Level 3 measurement. The significant unobservable inputs used include forecasted revenues, gross margins, discount rates, and terminal value exit multiples. The weighted average discount rate and exit multiples reflect management’s best estimate of inputs a market participant would use.

Due to the recording of these impairments, we adjusted the valuation allowance we had recorded as of December 31, 2019 to reflect the expected realizability of deferred tax assets. The valuation allowance, in addition to state income taxes and the impact of permanent differences between book and taxable income, results in a difference between amounts computed by applying the federal statutory rate to pre-tax loss for the two and eight months ended August 31, 2020.

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Oil and Natural Gas Properties

During the first quarter of 2020, we determined that because of the increased uncertainty in our business our undeveloped acreage would not be fully developed and thus the carrying values of certain of our unproved oil and gas properties were not recoverable resulting in an impairment of $226.5 million. That impairment had a corresponding increase to our depletion base and contributed to our recorded full cost ceiling impairment during the first quarter of 2020. We recorded a non-cash full cost ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax) in the first quarter of 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. The 12-month average commodity prices decreased further, resulting in non-cash ceiling test write-downs of $109.3 million in the second quarter of 2020 and $16.6 million in the two months ended August 31, 2020. In the third quarter of 2019, we determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $50.0 million of cost being added to the total of our capitalized costs being amortized in the third quarter of 2019. We incurred a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax) in the third quarter of 2019.

In addition to the impairment evaluations of our proved and unproved oil and gas properties in the first quarter of 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast of the use of those assets, we determined that some of those assets were no longer expected to be used and we wrote off those salt water disposal assets that we now consider abandoned. We recorded total expense of $17.6 million related to the write-down of those salt water disposal assets for the eight months ended August 31, 2020. These amounts are reported in loss on abandonment of assets in our Unaudited Condensed Consolidated Statements of Operations.

Contract Drilling

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

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

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

We recorded expense of $1.1 million related to the write-down of certain equipment in the third quarter of 2020 that we now consider abandoned. These amounts are reported in loss on abandonment of assets in our Unaudited Condensed Consolidated Statements of Operations.

Mid-stream

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

No other impairment triggering events were identified during the two months ended August 31, 2020.

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NOTE 5 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is how we disaggregate our revenue and report our segment revenue (as reflected in Note 18 – Industry Segment Information). Revenue from the oil and natural gas segment is from sales of our oil and natural gas production. Revenue from the contract drilling segment comes from contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas and NGLs and selling those commodities.

Oil and Natural Gas Revenues

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

Contract Drilling Revenues

The impact from the mobilization and de-mobilization charges due under our outstanding drilling contracts to our financial statements was immaterial. As of September 30, 2020, we had eight contract drilling contracts with terms ranging from two months to almost two years.

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

Mid-stream Contracts Revenues

Revenues are generated from fees earned for gas gathering and processing services provided to a customer. The typical revenue contracts used by this segment are gas gathering and processing agreements. These tables show the changes in our mid-stream contract asset and contract liability balances during the nine months ended September 30, 2020:


	Successor		Predecessor
	September 30, 2020		December 31, 2019		Change
	(In thousands)
Contract assets	$	7,976	$	12,921	$	(4,945)
Contract liabilities	4,899		7,061		(2,162)
Contract assets (liabilities), net	$	3,077	$	5,860	$	(2,783)

The amounts above are reported in prepaid expenses and other, other assets (long-term), current portion of other long-term liabilities, and other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets.

Below is the fixed revenue Superior will earn over the remaining term of the contracts, excluding all variable consideration to be earned with the associated contract.


Contract	Remaining Term of Contract	October - December 2020		2021		2022		2023 and beyond		Total Remaining Impact to Revenue
		(In thousands)
Demand fee contracts	2-8 years	$	(992)	$	(3,501)	$	1,380	$	36	$	(3,077)

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NOTE 6 – DIVESTITURES

Successor

For the one month ended September 30, 2020, there were no significant divestitures.

Predecessor

Oil and Natural Gas

We sold $1.2 million of non-core oil and natural gas assets, net of related expenses, during the first eight months of 2020, compared to $2.2 million during the first nine months of 2019. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.

Contract Drilling

As of December 31, 2019, we had seven drilling rigs and other drilling equipment to be marketed for sale during the next twelve months, which we classified as assets held for sale with a fair value of $5.9 million. During the first quarter of 2020, due to market conditions, it was determined these assets would not be sold in the next twelve months and were reclassified to long-lived assets.

NOTE 7 – EARNINGS (LOSS) PER SHARE

Successor

On the Effective Date, the company issued 12.0 million shares of New Common Stock to a trustee to be subsequently distributed in accordance with the Plan.

Information related to the calculation of earnings (loss) per share attributable to the company is as follows:


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the one month ended September 30, 2020
Basic loss attributable to Unit Corporation per common share	$	(8,968)	12,000	$	(0.75)

Predecessor

Information related to the calculation of earnings (loss) per share attributable to the company is as follows:


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the two months ended August 31, 2020
Basic earnings attributable to Unit Corporation per common share	$	55,131	53,519	$	1.03


For the three months ended September 30, 2019
Basic loss attributable to Unit Corporation per common share	$	(206,886)	52,950	$	(3.91)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(206,886)	52,950	$	(3.91)

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


	Three Months Ended
	September 30,
	2019
Stock options	42,000
Average exercise price	$	48.56


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the eight months ended August 31, 2020
Basic loss attributable to Unit Corporation per common share	$	(931,012)	53,368	$	(17.45)


For the nine months ended September 30, 2019
Basic loss attributable to Unit Corporation per common share	$	(218,899)	52,814	$	(4.14)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(218,899)	52,814	$	(4.14)

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


	Nine Months Ended
	September 30,
	2019
Stock options	42,000
Average exercise price	$	48.56

NOTE 8 – ACCRUED LIABILITIES

Accrued liabilities consisted of:


	Successor		Predecessor
	September 30, 2020		December 31, 2019
	(In thousands)
Taxes	$	8,497	$	3,450
Employee costs	6,779		17,832
Lease operating expenses	6,395		9,200
Legal settlement	2,655		—
Interest payable	857		6,562
Third-party credits	—		3,691
Other	2,992		5,827
Total accrued liabilities	$	28,175	$	46,562

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

Long-Term Debt

As of the date indicated, our debt consisted of the following:


	Successor		Predecessor
	September 30, 2020		December 31, 2019
	(In thousands)
Current portion of long-term debt:
Predecessor credit facility with an average interest rate of 4.0%	$	—	$	108,200
Successor Exit Facility with an average interest rate of 6.6%	400		—
Long-term debt:
Successor Exit Facility with an average interest rate of 6.6%	131,600		—
Superior credit agreement with an average interest rate of 2.1% and 3.9% at September 30, 2020 and December 31, 2019, respectively	12,000		16,500
Predecessor 6.625% senior subordinated notes due 2021	—		650,000
Total principal amount	143,600		666,500
Less: unamortized discount	—		(971)
Less: debt issuance costs, net	—		(2,313)
Total long-term debt	$	143,600	$	663,216

The Debtors' filing of the Bankruptcy Petitions constituted an event of default that accelerated the Debtors' obligations under the Unit credit agreement, which are reflected as current liabilities as of December 31, 2019.

Successor 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 (new term loan facility and together with the new RBL facility, the Exit Facility), among (i) the company, UDC, and UPC (together, the Borrowers), (ii) the guarantors party thereto, including the company and all of its subsidiaries existing as of the Effective Date (other than Superior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders party thereto from time to time (Lenders), and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (in such capacity, the Administrative Agent).

The maturity date of borrowings under this Exit credit agreement is March 1, 2024. Revolving Loans and Term Loans (each as defined in the Exit credit agreement) may be Eurodollar Loans or ABR Loans (each as defined in the Exit credit agreement). Revolving Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate (as defined in the Exit credit agreement) for the applicable interest period plus 525 basis points. Revolving Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate (as defined in the Exit credit agreement) plus 425 basis points. Term Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate for the applicable interest period plus 625 basis points. Term Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate plus 525 basis points.

The Exit credit agreement requires the company to comply with certain financial ratios, including a covenant that the company will not permit the Net Leverage Ratio (as defined in the Exit credit agreement) as of the last day of the fiscal quarters ending (i) December 31, 2020 and March 31, 2021, to be greater than 4.00 to 1.00, (ii) June 30, 2021, September 30, 2021, December 31, 2021, March 31, 2022, and June 30, 2022, to be greater than 3.75 to 1.00, and (iii) September 30, 2022 and any fiscal quarter thereafter, to be greater than 3.50 to 1.00. In addition, beginning with the fiscal quarter ending December 31, 2020, the company may not (a) permit the Current Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 0.50 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, restrict certain asset sales and the related use of proceeds, and require certain hedging activities. The Exit credit agreement further requires the company provide Quarterly Financial Statements within 45 days after the end of each of the first three quarters of each fiscal year and Annual Financial Statements within 90 days after the end of each fiscal year. For the quarter ended September 30, 2020, the syndicate banks allowed for an extension.

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

On the Effective Date, the Borrowers had (i) $40.0 million in principal amount of Term Loans outstanding under the Term Loan Facility, (ii) $92.0 million in principal amount of Revolving Loans outstanding under the RBL Facility and (iii) approximately $6.7 million of outstanding letters of credit. At September 30, 2020, we had $0.4 million and $131.6 million outstanding current and long-term borrowings, respectively, under the Exit Facility.

Predecessor's Credit Agreement. Before the filing of the Chapter 11 Cases, the Unit credit facility had a scheduled maturity date of October 18, 2023 that would have accelerated to November 16, 2020 if, by that date, all the Notes were not repurchased, redeemed, or refinanced with indebtedness having a maturity date at least six months following October 18, 2023 (Credit Agreement Extension Condition). The Debtors' filing of the Bankruptcy Petitions constituted an event of default that accelerated the Debtors' obligations under the Unit credit agreement and the indenture governing the Notes. Due to the Credit Agreement Extension Condition and the acceleration of debt obligations resulting from filing the Chapter 11 Cases, the company's debt associated with the Predecessor's credit agreement is reflected as a current liability in its consolidated balance sheets as of September 30, 2020 and December 31, 2019. The classification as a current liability due to the Credit Agreement Extension Condition was based on the filing of the Chapter 11 Cases and the uncertainty regarding the company's ability to repay or refinance the Notes before November 16, 2020. In addition, on May 22, 2020, the RBL Lenders' remaining commitments under the Unit credit facility were terminated.

Before filing the Chapter 11 Cases, we were charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varied based on the amount borrowed as a percentage of the total borrowing base. Total amendment fees of $3.3 million in origination, agency, syndication, and other related fees were being amortized over the life of the Unit credit agreement. Due to the remaining commitments under the Unit credit agreement being terminated by the RBL Lenders', the unamortized debt issuance costs of $2.4 million were written off during the second quarter of 2020. Under the Predecessor credit agreement, we pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties. Under the mortgages covering those oil and gas properties, UPC also pledged certain items of its personal property.

On May 2, 2018, we entered into a Pledge Agreement with BOKF, NA (dba Bank of Oklahoma), as administrative agent to benefit the secured parties, under which we granted a security interest in the limited liability membership interests and other equity interests we own in Superior as additional collateral for our obligations under the Predecessor credit agreement.

Before to filing the Chapter 11 Cases, any part of the outstanding debt under the Predecessor credit agreement could be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest was computed as the LIBOR base for the term plus 1.50% to 2.50% depending on the level of debt as a percentage of the borrowing base and was payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest equal to the higher of the prime rate specified in the Predecessor credit agreement and the sum of the Federal Funds Effective Rate (as defined in the Unit credit agreement) plus 0.50%, but in no event would the interest on those borrowings be less than LIBOR plus 1.00% plus a margin. The Predecessor credit agreement provided that if ICE Benchmark Administration no longer reported the LIBOR or the Administrative Agent determined in good faith that the rate so reported no longer accurately reflected the rate available in the London Interbank Market or if the index no longer existed or accurately reflects the rate available to the Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index. Interest was payable at the end of each month or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty.

Filing the Bankruptcy Petitions on May 22, 2020 constituted an event of default that accelerated the company’s obligations under the Unit credit agreement, and the lenders’ rights of enforcement regarding the Predecessor credit agreement were automatically stayed because of the Chapter 11 Cases.

On the Effective Date, each lender under the Predecessor credit facility and the DIP credit facility received its pro rata share of revolving loans, term loans and letter-of-credit participations under the exit facility, in exchange for that lender’s allowed claims under the Predecessor credit facility or the DIP credit facility.

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(iii) the Thirty-Day LIBOR Rate (as defined in the Superior credit agreement plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by mortgage liens on certain of Superior’s processing plants and gathering systems. The Superior credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to the Administrative Agent in the London Interbank Market, the Administrative Agent may select a replacement index.

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

The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. The agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As of September 30, 2020, Superior complied with these covenants.

The Superior credit agreement is used to fund capital expenditures and acquisitions and provide general working capital and letters of credit.

Superior's credit agreement is not guaranteed by Unit. Superior and its subsidiaries were not Debtors in the Chapter 11 Cases.

Predecessor 6.625% Senior Subordinated Notes. The Predecessor's Notes were issued under an Indenture dated as of May 18, 2011, between the company and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for issuing the Notes.

As a result of Unit's emergence from bankruptcy, the Notes were cancelled and the Predecessor's liability thereunder was discharged as of the Effective Date, and the holders of the Notes were issued approximately 10.5 million shares of New Common Stock.

Predecessor DIP Credit Agreement. As contemplated by the RSA, the company and the other Debtors entered into a Superpriority Senior Secured Debtor-in-Possession Credit Agreement dated May 27, 2020 ( DIP credit agreement), among the Debtors, the RBL Lenders (in such capacity, the DIP Lenders), and BOKF, NA dba Bank of Oklahoma, as administrative agent, under which the DIP Lenders agreed to provide the company with the $36.0 million multiple-draw loan facility (DIP credit facility). The Bankruptcy Court entered an interim order on May 26, 2020 approving the DIP credit facility, permitting the Debtors to borrow up to $18.0 million on an interim basis. On June 19, 2020, the Bankruptcy Court granted final approval of the DIP credit facility.

Before its repayment and termination on the Effective Date, borrowings under the DIP credit facility matured on the earliest of (i) September 22, 2020 (subject to a two-month extension to be approved by the DIP Lenders), (ii) the sale of all or substantially all of the assets of the Debtors under Section 363 of the Bankruptcy Code or otherwise, (iii) the effective date of a plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an order by the Bankruptcy Court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code and (v) the date of termination of the DIP Lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP credit facility under and subject to the DIP credit agreement and the Bankruptcy Court’s orders.

On the Effective Date, the DIP credit agreement was paid in full and terminated. On the Effective Date, each holder of an allowed claim under the DIP credit facility received its pro rata share of revolving loans, term loans, and letter-of-credit participations under the exit facility. In addition, each holder was issued its pro rata share of an equity fee under the exit facility equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and on exercise of the Warrants).

For further information about the DIP credit agreement, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.

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Other Long-Term Liabilities

Other long-term liabilities consisted of the following:


	Successor		Predecessor
	September 30, 2020		December 31, 2019
	(In thousands)
Asset retirement obligation (ARO) liability	$	24,922	$	66,627
Workers’ compensation	11,664		11,510
Contract liability	4,899		7,061
Separation benefit plans (1)	4,536		10,122
Finance lease obligations	4,272		7,379
Gas balancing liability	3,824		3,838
Deferred compensation plan	—		6,180
Other long-term liability	1,997		—
	56,114		112,717
Less current portion	12,324		17,376
Total other long-term liabilities	$	43,790	$	95,341

_______________________

1.As of the Effective Date, the Board adopted (i) the Amended and Restated Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Separation Benefit Plan), (ii) the Amended and Restated Special Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Special Separation Benefit Plan) and (iii) the Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (New Separation Benefit Plan). In accordance with the Plan, the Amended Separation Benefit Plan and the Amended Special Separation Benefit Plan allow former employees or retained employees with vested severance benefits under either plan to receive certain cash payments in full satisfaction for their allowed separation claim under the Chapter 11 Cases. In accordance with the Plan, the New Separation Benefit Plan is a comprehensive severance plan for retained employees, including retained employees whose severance did not already vest under the Amended Separation Benefit Plan or the Amended Special Separation Benefit Plan. The New Separation Benefit Plan provides that eligible employees will be entitled to two weeks of severance pay per year of service, with a minimum of four weeks and a maximum of 13 weeks of severance pay.

NOTE 10 – ASSET RETIREMENT OBLIGATIONS (ARO)

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):





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

_______________________

1.Plugging liability estimates were revised in 2020 for updates in the cost of services used to plug wells over the preceding year and estimated dates to be plugged.

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






ARO liability, December 31, 2018 (Predecessor)	$	64,208
Accretion of discount	1,770
Liability incurred	4,325
Liability settled	(2,805)
Liability sold	(1,721)
Revision of estimates (1)	(1,705)
ARO liability, September 30, 2019 (Predecessor)	64,072
Less current portion	3,033
Total long-term ARO	$	61,039

_______________________

1.Plugging liability estimates were revised in 2019 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 11 – NEW ACCOUNTING PRONOUNCEMENTS

Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 which provides optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The ASU is intended to help stakeholders during the global market-wide reference rate transition period. The amendments within this ASU will be in effect for a limited time beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. The company is currently evaluating the impact this guidance may have on its consolidated financial statements.

Currently, there are no accounting pronouncements that have been issued, but not yet adopted, that are expected to have a material impact on our consolidated financial statements or related disclosures.

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Adopted Standards

Measurement of Credit Losses on Financial Instruments (Topic 326). The FASB issued ASU 2016-13 which replaces current methods for evaluating impairment of financial instruments not measured at fair value, including trade accounts receivable, and certain debt securities, with a current expected credit loss model ("CECL"). The CECL model is expected to result in more timely recognition of credit losses. The amendment was effective for reporting periods after December 15, 2019. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures.

Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were removed or modified, and other disclosures were added. The amendment was effective for reporting periods beginning after December 15, 2019. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures.

NOTE 12 – STOCK-BASED COMPENSATION

On the Effective Date, the company's equity-based awards that were outstanding immediately before the Effective Date were cancelled. The cancellation of the awards resulted in an acceleration of unrecorded stock compensation expense during the predecessor period. Under the Plan, the company issued Warrants to holders of those equity-based awards that were outstanding immediately before the Effective Date who did not opt out of releases under the Plan. For further information, see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.

Also 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, par value $0.01 per share (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.

The following table summarizes the amount recorded for stock-based compensation, which consisted of restricted stock awards and stock options, for the time periods shown:


	Predecessor
	Two Months Ended		Three Months Ended		Eight Months Ended		Nine Months Ended
	August 31,		September 30,		August 31,		September 30,
	2020		2019		2020		2019
	(In millions)
Recognized stock compensation expense (1)	$	2.0	$	4.5	$	6.1	$	13.0
Capitalized stock compensation cost for our oil and natural gas properties	—		0.7		—		2.0
Tax benefit on stock-based compensation	0.5		1.1		1.5		3.2

_______________________

1.When the company's equity-based awards were cancelled on the Effective Date, we immediately recognized the expense for the cancelled awards of $1.4 million as reorganization costs, net.

Our Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allowed us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) and to non-employee directors. There were 7,230,000 shares of the company's common stock authorized for issuance to eligible participants under the amended plan with 2,000,000 shares being the maximum number of shares that could be issued as "incentive stock options." This plan was terminated under the Plan.

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We did not grant any stock options during 2020 or 2019. We did not grant any restricted stock awards during 2020 or the three month period ending September 30, 2019. This table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated:


	Nine Months Ended
	September 30, 2019
		Time Vested			Performance Vested
Shares granted:
Employees		927,173			424,070
Non-employee directors		72,784			—
		999,957			424,070
Estimated fair value (in millions): (1)
Employees		$	14.6		$	7.1
Non-employee directors		0.9			—
		$	15.5		$	7.1
Percentage of shares granted expected to be distributed:
Employees		95		%	52		%
Non-employee directors		100		%	N/A

_______________________

1.The performance shares represent 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

The time vested restricted stock awards granted during the first nine months of 2019 were being recognized over a three-year vesting period. During the first quarter of 2019, two performance vested restricted stock awards were granted to certain executive officers. The first cliff vests three years from the grant date based on the company's achievement of certain stock performance measures (TSR) at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second vests, one-third each year, over a three-year vesting period subject to the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. These awards were cancelled on the Effective Date. We recognized a reversal of expense previously recorded for the unvested awards of $2.2 million for these awards upon cancellation.

NOTE 13 – DERIVATIVES

Commodity Derivatives

We have entered into various types of derivative transactions covering some of our projected natural gas and oil production during both the predecessor and successor periods. 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 of September 30, 2020, these hedges made up our derivative transactions:

•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 have documented policies and procedures to monitor and control the use of derivative transactions. We do not engage in derivative transactions not otherwise tied to our projected production. Any changes in the fair value of our derivative transactions before maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations.

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As of September 30, 2020, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Oct'20 - Dec'20

Natural gas - basis swap

30,000 MMBtu/day

$(0.275)

NGPL TEXOK

Oct'20 - Dec'20

Natural gas - basis swap

20,000 MMBtu/day

$(0.455)

PEPL

Jan'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$(0.215)

NGPL TEXOK

Oct'20 - Dec'20

Natural gas - swap

30,000 MMBtu/day

$2.753

IF - NYMEX (HH)

Jan'21 - Oct'21

Natural gas - swap

50,000 MMBtu/day

$2.818

IF - NYMEX (HH)

Nov'21 - Dec'21

Natural gas - swap

75,000 MMBtu/day

$2.880

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - swap

5,000 MMBtu/day

$2.605

IF - NYMEX (HH)

Jan'23 - Dec'23

Natural gas - swap

22,000 MMBtu/day

$2.456

IF - NYMEX (HH)

Oct'20 - Dec'20

Natural gas - collar

30,000 MMBtu/day

$2.50 - $2.80

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - collar

35,000 MMBtu/day

$2.50 - $2.68

IF - NYMEX (HH)

Oct'20 - Dec'20

Crude oil - swap

4,000 Bbl/day

$43.35

WTI - NYMEX

Jan'21 - Dec'21

Crude oil - swap

3,000 Bbl/day

$44.65

WTI - NYMEX

Jan'22 - Dec'22

Crude oil - swap

2,300 Bbl/day

$42.25

WTI - NYMEX

Jan'23 - Dec'23

Crude oil - swap

1,300 Bbl/day

$43.60

WTI - NYMEX

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


		Derivative Assets
		Fair Value
		Successor		Predecessor
	Balance Sheet Location	September 30, 2020		December 31, 2019
		(In thousands)
Commodity derivatives:
Current	Current derivative asset	$	2,367	$	633
Long-term	Non-current derivative asset	—		—
Total derivative assets		$	2,367	$	633


		Derivative Liabilities
		Fair Value
		Successor		Predecessor
	Balance Sheet Location	September 30, 2020		December 31, 2019
		(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	1,114	$	—
Long-term	Non-current derivative liability	1,749		27
Total derivative liabilities		$	2,863	$	27

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

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


	Successor		Predecessor
	One Month Ended		Two Months Ended		Three Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of ($1,418), ($3,552), and $6,515, respectively	$	3,939	$	(4,250)	$	4,237
	$	3,939	$	(4,250)	$	4,237


	Successor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of ($1,418), ($4,244), and $11,829, respectively	$	3,939	$	(10,704)	$	5,232
	$	3,939	$	(10,704)	$	5,232

NOTE 14 – FAIR VALUE MEASUREMENTS

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

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

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

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

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

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The following tables set forth our recurring fair value measurements:


	Successor
	September 30, 2020
	Level 2		Level 3		Effect of Netting		Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	3,929	$	—	$	(1,562)	$	2,367
Liabilities	(4,425)		—		1,562		(2,863)
Total commodity derivatives	$	(496)	$	—	$	—	$	(496)


	Predecessor
	December 31, 2019
	Level 2		Level 3		Effect of Netting		Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	177	$	1,204	$	(748)	$	633
Liabilities	(775)		—		748		(27)
Total commodity derivatives	$	(598)	1,204		—		606

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, 2020.

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

Level 2 Fair Value Measurements

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

Level 3 Fair Value Measurements

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

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


	Net Derivatives
	Successor		Predecessor
	One Month Ended		Two Months Ended		Three Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Beginning of period	$	—	$	843	$	3,945
Total gains or losses (realized and unrealized):
Included in earnings (1)	—		(405)		2,393
Settlements	—		(437)		(3,627)
End of period	$	—	$	—	$	2,711
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)	$	(1,234)

_______________________

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

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


	Net Derivatives
	Successor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Beginning of period	$	—	$	1,204	$	10,630
Total gains or losses (realized and unrealized):
Included in earnings (1)	—		872		(980)
Settlements	—		(2,075)		(6,939)
End of period	—		—		$	2,711
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	$	—	$	(1,204)	$	(7,919)

_______________________

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

Our valuation at September 30, 2020 reflected that the risk of non-performance was immaterial.

Fair Value of Other Financial Instruments

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

At September 30, 2020, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (composed of bank and money market accounts - classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature.

The carrying amounts of long-term debt associated with the Notes, net of unamortized discount and debt issuance costs, reported in the Unaudited Condensed Consolidated Balance Sheets as of December 31, 2019 were $646.7 million. On the Effective Date, our obligations with respect to the Notes were cancelled and holders of the Notes received their agreed on pro-rata share of New Common Stock. For further information, please see Note 2 – Emergence From Voluntary Reorganization

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Under Chapter 11. The estimated fair value of the Notes using quoted market prices at December 31, 2019 was $357.5 million. The Notes were classified as Level 2.

Fair Value of Non-Financial Instruments

The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of our AROs is presented in Note 10 – Asset Retirement Obligations.

NOTE 15 – LEASES

We lease certain office space, land and equipment, including pipeline equipment and office equipment. Our lease payments are generally straight-line and exercising 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 renewal options. Our lease agreements do not include options to purchase the leased property.

Related to our oil and natural gas segment, our short-term lease costs include those that are recognized in profit or loss during the period and those that are capitalized as part of the cost of another asset under GAAP. As the costs related to our drilling and production activities are reflected at our net ownership consistent with the principals of proportional consolidation, and lease commitments are generally considered gross as the operator, the costs may not reasonably reflect the company’s short-term lease commitments.

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


	Successor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	351	$	3,849	$	2,862
Financing cash flows for finance leases	350		2,757		2,984
Lease liabilities recognized in exchange for new operating lease right of use assets	—		—		5

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


		Successor		Predecessor
	Classification on the Consolidated Balance Sheets	September 30, 2020		December 31, 2019
		(In thousands)
Assets
Operating right of use assets	Right of use assets	$	6,488	$	5,673
Finance right of use assets	Property, plant, and equipment, net	15,985		17,396
Total right of use assets		$	22,473	$	23,069

Liabilities
Current liabilities:
Operating lease liabilities	Current operating lease liabilities	$	3,985	$	3,430
Finance lease liabilities	Current portion of other long-term liabilities	4,272		4,164
Non-current liabilities:
Operating lease liabilities	Operating lease liabilities	2,431		2,071
Finance lease liabilities	Other long-term liabilities	—		3,215
Total lease liabilities		$	10,688	$	12,880

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



	Successor		Predecessor
	One Month Ended		Two Months Ended		Three Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Components of total lease cost:
Amortization of finance leased assets	$	350	$	696	$	1,005
Interest on finance lease liabilities	15		35		91
Operating lease cost	328		965		1,267
Short-term lease cost, included are amounts capitalized related to our oil and natural gas segment of less than $0.1 million, $0.1 million, and $7.0 million, respectively	867		1,448		10,841
Variable lease cost	29		58		93
Total lease cost	$	1,589	$	3,202	$	13,297

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	Successor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Components of total lease cost:
Amortization of finance leased assets	$	350	$	2,757	$	2,985
Interest on finance lease liabilities	15		165		302
Operating lease cost	328		3,604		2,915
Short-term lease cost, included are amounts capitalized related to our oil and natural gas segment of less than $0.1 million, $1.5 million, and $21.7 million, respectively	867		8,190		32,857
Variable lease cost	29		223		283
Total lease cost	$	1,589	$	14,939	$	39,341

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


	Weighted Average Remaining Lease Term	Weighted Average Discount Rate (1)
	(In years)
Operating leases	1.6	4.04%
Finance leases	0.9	4.00%

_______________________

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

The following table sets forth the maturity of our operating lease liabilities as of September 30, 2020:


	Amount
	(In thousands)
Ending October 1,
2021	$	4,184
2022	2,241
2023	157
2024	18
2025	12
2025 and beyond	66
Total future payments	6,678
Less: Interest	262
Present value of future minimum operating lease payments	6,416
Less: Current portion	3,985
Total long-term operating lease payments	$	2,431

Finance Leases

In 2014, Superior entered into finance lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $4.3 million current portion of the finance lease obligations is included in current portion of other long-term liabilities is included in other long-term liabilities in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2020. These finance leases are discounted using annual rates of

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4.00%. Total maintenance and interest remaining related to these leases are $1.0 million and $0.1 million, respectively, at September 30, 2020. Annual payments, net of maintenance and interest, average $4.7 million annually through 2021. At the end of the term, Superior has the option to purchase the assets at 10% of their then fair market value.

The following table sets forth the maturity of our finance lease liabilities as of September 30, 2020:


	Amount
Ending October 1,	(In thousands)
2021	$	5,323
Total future payments	5,323
Less payments related to:
Maintenance	978
Interest	73
Present value of future minimum finance lease payments	4,272
Less: Current portion	4,272
Total long-term finance lease payments	$	—

NOTE 16 – COMMITMENTS AND CONTINGENCIES

On May 22, 2020, the Debtors filed the Bankruptcy Petitions seeking relief under the Bankruptcy Code. The commencement of the Chapter 11 Cases automatically stayed all of 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 Plan. For further information on the Chapter 11 Cases, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.

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

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

During the second quarter of 2018, as part of the Superior transaction, we entered into a contractual obligation committing us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. For each dollar of the $150.0 million we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our ownership interest in our consolidated mid-stream subsidiary. At September 30, 2020, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.6 million. The total amount spent towards the $150.0 million as of September 30, 2020 was $24.8 million.

We have firm transportation commitments to transport our natural gas from various systems for approximately $1.2 million over the next twelve months and $0.5 million for the 15 months thereafter.

The company is subject to litigation and claims arising in the ordinary course of business. 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 as a result 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.

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In 2013, the company’s exploration and production subsidiary, Unit Petroleum Company (UPC), drilled a well in Beaver County, Oklahoma. Certain operational issues arose and one of the working interest owners in the well filed a lawsuit claiming that UPC’s actions violated its duties under the joint operating agreement and caused damages to the owners in the well. The case went to trial in January 2019 and the jury issued a verdict in favor of Williford and awarded it $2.4 million in damages, including pre and post-judgment interest. UPC appealed the verdict and it is currently pending review in in the Oklahoma Court of Civil Appeals. As of September 30, 2020, the company's total accrual for loss contingencies was $2.7 million.

Below is a summary of two other lawsuits and the respective treatment of those cases in the Bankruptcy Proceedings.

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 Unit Petroleum Company styled Cockerell Oil Properties, Ltd., v. Unit Petroleum Company in LeFlore County, Oklahoma. We removed the case to federal court in the Eastern District of Oklahoma. The plaintiff alleges that Unit Petroleum 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 Unit Petroleum Company styled Chieftain Royalty Company v. Unit Petroleum Company in LeFlore County, Oklahoma. Plaintiff alleges that Unit Petroleum breached its duty to pay royalties on natural gas used for fuel off the lease premises. The lawsuit seeks actual and punitive damages, an accounting, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of Oklahoma citizens who are or were royalty owners in our Oklahoma wells.

Pending Settlement

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

NOTE 17 – VARIABLE INTEREST ENTITY ARRANGEMENTS

On April 3, 2018 we sold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior will be governed and managed under the Amended and Restated Limited Liability Company Agreement and a Management Services Agreement (MSA). The MSA is between our affiliate, SPC Midstream Operating, L.L.C. (Operator) and Superior. The Operator is a wholly owned subsidiary of Unit. 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, 2020.

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, and all intercompany balances and transactions between us and the VIE are eliminated in our consolidated financial statements. Cash distributions of income, net of agreed on expenses, and estimated expenses are allocated to the equity owners as specified in the relevant agreements. With consolidation of the VIE, the assets and liabilities of Superior were subject to fair value adjustments in accordance with ASC 852, Reorganizations. Therefore, the periods presented below are not comparative as the amounts presented as of September 30, 2020 reflect the adjustments from Note 3 – Fresh Start Accounting.

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The Agreement specifies how future distributions are to be allocated among the Members. Future distributions may be from available cash or made in conjunction with a sale event (both as defined in the Agreement). In certain circumstances, future distributions could result in Unit receiving distributions that are disproportionately lower than its ownership percentage. Circumstances that could result in Unit receiving less than a proportionate share of future distributions include, but may not be limited to, Unit does not fulfill the drilling commitment described in Note 16 – Commitments and Contingencies or a cumulative return to SP Investor Holdings, LLC of less than the 7% Liquidation IRR Hurdle provided for SP Investor Holdings, LLC in the Agreement. Generally, 7% Liquidation IRR Hurdle calculation requires cumulative distributions to SP Investor Holdings, LLC in excess of its original $300.0 million investment sufficient to provide SP Investor Holdings, LLC a 7% IRR on its capital contributions to Superior before any liquidation distribution is made to Unit. After the fifth anniversary of the effective date of the sale, either owner may force a sale of Superior to a third-party or a liquidation of Superior's assets.

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

As the Operator, we provide services, like operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $260,560. Superior's creditors have no recourse to our general credit. Superior's credit agreement is not guaranteed by Unit. 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 carrying value of Superior's assets and liabilities, after eliminations of any intercompany transactions and balances, in the consolidated balance sheets is included below. The assets and liabilities of Superior are reflected at estimated fair value at September 30, 2020 as part of the company’s application of fresh start accounting as described in Note 3 - Fresh Start Accounting. The asset and liabilities at December 31, 2019 reflect historical basis prior to any fresh start accounting adjustments.


	September 30, 2020		December 31, 2019
	(In thousands)

Current assets:
Cash and cash equivalents	$	15,320	$	—
Accounts receivable	23,562		21,073
Prepaid expenses and other	7,034		7,686
Total current assets	45,916		28,759
Property and equipment:
Gas gathering and processing equipment	250,608		824,699
Transportation equipment	1,888		3,390
	252,496		828,089
Less accumulated depreciation, depletion, amortization, and impairment	2,658		407,144
Net property and equipment	249,838		420,945
Right of use asset	3,259		3,948
Other assets	3,928		9,442
Total assets	$	302,941	$	463,094

Current liabilities:
Accounts payable	$	11,894	$	18,511
Accrued liabilities	5,849		4,198
Current operating lease liability	1,752		2,407
Current portion of other long-term liabilities	7,051		7,060
Total current liabilities	26,546		32,176
Long-term debt	12,000		16,500
Operating lease liability	1,457		1,404
Other long-term liabilities	2,119		8,126
Total liabilities	$	42,122	$	58,206

NOTE 18 – INDUSTRY SEGMENT INFORMATION

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

•Oil and natural gas,

•Contract drilling, and

•Mid-stream

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

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

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


	Successor
	One Month Ended September 30, 2020
	Oil and Natural Gas		Contract Drilling		Mid-stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	13,644	$	—	$	—	$	—	$	(1)	$	13,643
Contract drilling	—		4,414		—		—		—		4,414
Gas gathering and processing	—		—		17,284		—		(2,495)		14,789
Total revenues	13,644		4,414		17,284		—		(2,496)		32,846
Expenses:
Operating costs:
Oil and natural gas	6,892		—		—		—		(218)		6,674
Contract drilling	—		2,989		—		—		—		2,989
Gas gathering and processing	—		—		12,130		—		(2,278)		9,852
Total operating costs	6,892		2,989		12,130		—		(2,496)		19,515
Depreciation, depletion, and amortization	4,199		526		2,658		84		—		7,467
Impairments	13,237		—		—		—		—		13,237
Total expenses	24,328		3,515		14,788		84		(2,496)		40,219

General and administrative	—		—		—		1,582		—		1,582
Gain on disposition of assets	(10)		(212)		—		—		—		(222)
Income (loss) from operations	(10,674)		1,111		2,496		(1,666)		—		(8,733)
Gain on derivatives	—		—		—		3,939		—		3,939
Reorganization items, net	—		—		—		(1,155)		—		(1,155)
Interest, net	—		—		(137)		(689)		—		(826)
Other	29		1		8		1		—		39
Income (loss) before income taxes	$	(10,645)	$	1,112	$	2,367	$	430	$	—	$	(6,736)

_______________________

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

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	Predecessor
	Two Months Ended August 31, 2020
	Oil and Natural Gas		Contract Drilling		Mid-stream			Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	27,962	$	—	$	—		$	—	$	(1)	$	27,961
Contract drilling	—		7,685		—			—		—		7,685
Gas gathering and processing	—		—		34,132			—		(4,204)		29,928
Total revenues	27,962		7,685		34,132			—		(4,205)		65,574
Expenses:
Operating costs:
Oil and natural gas	15,895		—		—			—		(407)		15,488
Contract drilling	—		5,410		—			—		—		5,410
Gas gathering and processing	—		—		21,620			—		(3,798)		17,822
Total operating costs	15,895		5,410		21,620			—		(4,205)		38,720
Depreciation, depletion, and amortization	9,975		853		6,750			341		—		17,919
Impairments	16,572		—		—			—		—		16,572
Total expenses	42,442		6,263		28,370			341		(4,205)		73,211
Loss on abandonment of assets	87		1,092		—			—		—		1,179
General and administrative	—		—		—			5,399		—		5,399
Gain on disposition of assets	(102)		(1,251)		(3)		0	—		—		(1,356)
Income (loss) from operations	(14,465)		1,581		5,765			(5,740)		—		(12,859)
Loss on derivatives	—		—		—			(4,250)		—		(4,250)

Reorganization items, net	15,504		(183,664)		(71,016)			380,178		—		141,002
Interest, net	—		—		(828)			(1,131)		—		(1,959)
Other	428		1,426		11			66		—		1,931
Income (loss) before income taxes	$	1,467	$	(180,657)	$	(66,068)		$	369,123	$	—	$	123,865

_______________________

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

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	Predecessor
	Three Months Ended September 30, 2019
	Oil and Natural Gas		Contract Drilling		Mid-stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	78,045	$	—	$	—	$	—	$	—	$	78,045
Contract drilling	—		38,626		—		—		(1,030)		37,596
Gas gathering and processing	—		—		48,585		—		(8,787)		39,798
Total revenues	78,045		38,626		48,585		—		(9,817)		155,439
Expenses:
Operating costs:
Oil and natural gas	36,621		—		—		—		(1,257)		35,364
Contract drilling	—		29,913		—		—		(1,117)		28,796
Gas gathering and processing	—		—		36,023		—		(7,530)		28,493
Total operating costs	36,621		29,913		36,023		—		(9,904)		92,653
Depreciation, depletion, and amortization	43,587		12,845		11,847		1,935		—		70,214
Impairments	169,806		62,809		2,265		—		—		234,880
Total expenses	250,014		105,567		50,135		1,935		(9,904)		397,747
General and administrative	—		—		—		10,094		—		10,094
(Gain) loss on disposition of assets	(28)		288		(28)		(1)		—		231
Income (loss) from operations	(171,941)		(67,229)		(1,522)		(12,028)		87		(252,633)
Gain on derivatives	—		—		—		4,237		—		4,237
Interest, net	—		—		(448)		(9,086)		—		(9,534)
Other	—		(627)		—		5		—		(622)
Income (loss) before income taxes	$	(171,941)	$	(67,856)	$	(1,970)	$	(16,872)	87		$	(258,552)

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

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

_______________________ ____________________

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

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	Predecessor
	Nine Months Ended September 30, 2019
	Oil and Natural Gas		Contract Drilling		Mid-stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: (1)
Oil and natural gas	$	241,955	$	—	$	—	$	—	$	—	$	241,955
Contract drilling	—		147,598		—		—		(15,810)		131,788
Gas gathering and processing	—		—		173,724		—		(37,191)		136,533
Total revenues	241,955		147,598		173,724		—		(53,001)		510,276
Expenses:
Operating costs:
Oil and natural gas	108,148		—		—		—		(3,828)		104,320
Contract drilling	—		103,688		—		—		(14,183)		89,505
Gas gathering and processing	—		—		133,702		—		(33,363)		100,339
Total operating costs	108,148		103,688		133,702		—		(51,374)		294,164
Depreciation, depletion, and amortization	118,105		39,048		35,675		5,804		—		198,632
Impairments	169,806		62,809		2,265		—		—		234,880
Total expenses	396,059		205,545		171,642		5,804		(51,374)		727,676
General and administrative	—		—		—		29,899		—		29,899
(Gain) loss on disposition of assets	(166)		1,737		(136)		(11)		—		1,424
Income (loss) from operations	(153,938)		(59,684)		2,218		(35,692)		(1,627)		(248,723)
Gain on derivatives	—		—		—		5,232		—		5,232
Interest, net	—		—		(1,129)		(25,938)		—		(27,067)
Other	—		(627)		—		16		—		(611)
Income (loss) before income taxes	$	(153,938)	$	(60,311)	$	1,089	(56,382)		$	(1,627)	$	(271,169)

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

NOTE 19 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

For the following footnote:

•we 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. It should be noted that the financial statements for the successor period are not comparable to those of the predecessor period as a result of the fresh start accounting adjustments described in Note 3 - Fresh Start Accounting.

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Condensed Consolidating Balances Sheets (Unaudited)


	Predecessor
	December 31, 2019
	Parent			Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	503		$	68	$	—	$	—	$	571
Accounts receivable, net of allowance for doubtful accounts of $2,332 (Guarantor of $1,116 and Parent of $1,216)	2,645			64,805		24,653		(9,447)		82,656
Materials and supplies	—			449		—		—		449
Current derivative asset	633			—		—		—		633
Income tax receivable	1,756		—	—		—		—		1,756
Assets held for sale	—			5,908		—		—		5,908
Prepaid expenses and other	2,019			3,373		7,686		—		13,078
Total current assets	7,556			74,603		32,339		(9,447)		105,051
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties	—			6,341,582		—		—		6,341,582
Unproved properties not being amortized	—			252,874		—		—		252,874
Drilling equipment	—			1,295,713		—		—		1,295,713
Gas gathering and processing equipment	—			—		824,699		—		824,699
Saltwater disposal systems	—			69,692		—		—		69,692
Corporate land and building	—			59,080		—		—		59,080
Transportation equipment	9,712			16,621		3,390		—		29,723
Other	28,927			29,065		—		—		57,992
	38,639			8,064,627		828,089		—		8,931,355
Less accumulated depreciation, depletion, amortization, and impairment	33,794			6,537,731		407,144		—		6,978,669
Net property and equipment	4,845			1,526,896		420,945		—		1,952,686
Intercompany receivable	1,048,785			—		—		(1,048,785)		—
Investments	865,252			—		—		(865,252)		—
Right of use asset	46			1,733		3,948		(54)		5,673
Other assets	8,107			9,094		9,441		—		26,642
Total assets	$	1,934,591		$	1,612,326	$	466,673	$	(1,923,538)	$	2,090,052

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	Predecessor
	December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	12,259	$	61,002	$	18,511	$	(7,291)	$	84,481
Accrued liabilities	28,003		14,024		6,691		(2,156)		46,562
Current operating lease liability	20		1,009		2,407		(6)		3,430
Current portion of long-term debt	108,200		—		—		—		108,200
Current portion of other long-term liabilities	3,003		7,313		7,060		—		17,376
Total current liabilities	151,485		83,348		34,669		(9,453)		260,049
Intercompany debt	—		1,047,599		1,186		(1,048,785)		—
Long-term debt less debt issuance costs	646,716		—		16,500		—		663,216
Non-current derivative liability	27		—		—		—		27
Operating lease liability	25		690		1,404		(48)		2,071
Other long-term liabilities	12,553		74,662		8,126		—		95,341
Deferred income taxes	68,150		(54,437)		—		—		13,713









Total shareholders' equity	1,055,635		460,464		404,788		(865,252)		1,055,635
Total liabilities and shareholders’ equity	$	1,934,591	$	1,612,326	$	466,673	$	(1,923,538)	$	2,090,052

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Condensed Consolidating Statements of Operations (Unaudited)


	Predecessor
	Two Months Ended August 31, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	35,647	$	34,132	$	(4,205)	$	65,574
Expenses:
Operating costs	—		21,307		21,619		(4,206)		38,720
Depreciation, depletion, and amortization	341		10,828		6,750		—		17,919
Impairments	—		16,572		—		—		16,572
Loss on abandonment of assets	—		1,179		—		—		1,179
General and administrative	—		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


	Predecessor
	Three Months Ended September 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	116,671	$	48,585	$	(9,817)	$	155,439
Expenses:
Operating costs	—		66,534		36,023		(9,904)		92,653
Depreciation, depletion, and amortization	1,935		56,432		11,847		—		70,214
Impairments	—		232,615		2,265		—		234,880
General and administrative	—		10,094		—		—		10,094
(Gain) loss on disposition of assets	(1)		260		(28)		—		231
Total operating costs	1,934		365,935		50,107		(9,904)		408,072
Income (loss) from operations	(1,934)		(249,264)		(1,522)		87		(252,633)
Interest, net	(9,086)		—		(448)		—		(9,534)
Gain on derivatives	4,237		—		—		—		4,237
Other, net	5		(627)		—		—		(622)
Loss before income taxes	(6,778)		(249,891)		(1,970)		87		(258,552)
Income tax benefit	(1,982)		(48,781)		—		—		(50,763)
Equity in net earnings from investment in subsidiaries, net of taxes	(202,090)		—		—		202,090		—
Net loss	(206,886)		(201,110)		(1,970)		202,177		(207,789)
Less: net loss attributable to non-controlling interest	—		—		(903)		—		(903)
Net loss attributable to Unit Corporation	$	(206,886)	$	(201,110)	$	(1,067)	$	202,177	$	(206,886)

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


	Predecessor
	Nine Months Ended September 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	389,553	$	173,724	$	(53,001)	$	510,276
Expenses:
Operating costs	—		211,836		133,702		(51,374)		294,164
Depreciation, depletion, and amortization	5,804		157,153		35,675		—		198,632
Impairments	—		232,615		2,265		—		234,880
General and administrative	—		29,899		—		—		29,899
(Gain) loss on disposition of assets	(11)		1,571		(136)		—		1,424
Total operating costs	5,793		633,074		171,506		(51,374)		758,999
Income (loss) from operations	(5,793)		(243,521)		2,218		(1,627)		(248,723)
Interest, net	(25,938)		—		(1,129)		—		(27,067)
Gain on derivatives	5,232		—		—		—		5,232
Other, net	16		(627)		—		—		(611)
Income (loss) before income taxes	(26,483)		(244,148)		1,089		(1,627)		(271,169)
Income tax benefit	(6,529)		(46,552)		—		—		(53,081)
Equity in net earnings from investment in subsidiaries, net of taxes	(198,945)		—		—		198,945		—
Net income (loss)	(218,899)		(197,596)		1,089		197,318		(218,088)
Less: net income attributable to non-controlling interest	—		—		811		—		811
Net income (loss) attributable to Unit Corporation	$	(218,899)	$	(197,596)	$	278	$	197,318	$	(218,899)

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Condensed Consolidating Statements of Comprehensive Income (Loss) (Unaudited)


	Predecessor
	Two Months ended August 31, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net income (loss)	$	128,615	$	(184,592)	$	(66,068)	$	250,660	$	128,615
Other comprehensive income (loss), net of taxes:
Unrealized gain on securities, net of tax of $0	—		—		—		—		—
Comprehensive income (loss)	128,615		(184,592)		(66,068)		250,660		128,615
Less: Comprehensive income attributable to non-controlling interests	73,484		—		73,484		(73,484)		73,484
Comprehensive income (loss) attributable to Unit Corporation	$	55,131	$	(184,592)	$	(139,552)	$	324,144	$	55,131


	Predecessor
	Three Months Ended September 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net loss	$	(206,886)	$	(201,110)	$	(1,970)	$	202,177	$	(207,789)
Other comprehensive loss, net of taxes:
Reclassification adjustment for write-down of securities, net of tax ($45)	—		487		—		—		487
Comprehensive loss	(206,886)		(200,623)		(1,970)		202,177		(207,302)
Less: Comprehensive loss attributable to non-controlling interests	—		—		(903)		—		(903)
Comprehensive loss attributable to Unit Corporation	$	(206,886)	$	(200,623)	$	(1,067)	$	202,177	$	(206,399)


	Predecessor
	Eight Months Ended August 31, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net loss	$	(890,624)	$	(1,108,875)	$	(132,246)	$	1,241,121	$	(890,624)
Other comprehensive loss, net of taxes:
Unrealized gain on securities, net of tax of $0	—		—		—		—		—
Comprehensive loss	(890,624)		(1,108,875)		(132,246)		1,241,121		(890,624)
Less: Comprehensive income attributable to non-controlling interests	40,388		—		40,388		(40,388)		40,388
Comprehensive loss attributable to Unit Corporation	$	(931,012)	$	(1,108,875)	$	(172,634)	$	1,281,509	$	(931,012)

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	Predecessor
	Nine Months Ended September 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net income (loss)	$	(218,899)	$	(197,596)	$	1,089	$	197,318	$	(218,088)
Other comprehensive income (loss), net of taxes:
Reclassification adjustment for write-down of securities, net of tax ($45)	—		481		—		—		481
Comprehensive income (loss)	(218,899)		(197,115)		1,089		197,318		(217,607)
Less: Comprehensive income attributable to non-controlling interests	—		—		811		—		811
Comprehensive income (loss) attributable to Unit Corporation	$	(218,899)	$	(197,115)	$	278	$	197,318	$	(218,418)

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Condensed Consolidating Statements of Cash Flows (Unaudited)


	Predecessor
	Eight Months Ended August 31, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(207,593)	$	82,769	$	32,922	$	136,858	$	44,956
INVESTING ACTIVITIES:
Capital expenditures	(986)		(14,585)		(10,204)		—		(25,775)
Producing properties and other acquisitions	—		(382)		—		—		(382)
Proceeds from disposition of assets	1,169		4,772		77		—		6,018
Net cash provided by (used in) investing activities	183		(10,195)		(10,127)		—		(20,139)
FINANCING ACTIVITIES:
Borrowings under credit agreement, including borrowings under DIP credit facility	55,300		—		32,100		—		87,400
Payments under credit agreement	(31,500)		—		(32,600)		—		(64,100)
DIP financing costs	(990)		—		—		—		(990)
Exit facility financing costs	(3,225)		—		—		—		(3,225)
Intercompany borrowings (advances), net	210,398		(72,642)		(898)		(136,858)		—
Payments on finance leases	—		—		(2,757)		—		(2,757)
Employee taxes paid by withholding shares	(43)		—		—		—		(43)
Bank overdrafts	(7,269)		—		(1,464)		—		(8,733)
Net cash provided by (used in) financing activities	222,671		(72,642)		(5,619)		(136,858)		7,552
Net increase (decrease) in cash and cash equivalents	15,261		(68)		17,176		—		32,369
Cash and cash equivalents, beginning of period	503		68		—		—		571
Cash and cash equivalents, end of period	$	15,764	$	—	$	17,176	$	—	$	32,940

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	Predecessor
	Nine Months Ended September 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	11,054	$	169,838	$	38,592	$	(34)	$	219,450
INVESTING ACTIVITIES:
Capital expenditures	168		(321,840)		(43,282)		—		(364,954)
Producing properties and other acquisitions	—		(3,345)		—		—		(3,345)
Proceeds from disposition of assets	11		10,376		119		—		10,506
Net cash provided by (used in) investing activities	179		(314,809)		(43,163)		—		(357,793)
FINANCING ACTIVITIES:
Borrowings under credit agreement	332,300		—		59,900		—		392,200
Payments under credit agreement	(198,200)		—		(55,800)		—		(254,000)
Intercompany borrowings (advances), net	(143,692)		144,867		(1,209)		34		—
Payments on finance leases	—		—		(2,984)		—		(2,984)
Employee taxes paid by withholding shares	(4,080)		—		—		—		(4,080)
Distributions to non-controlling interest	919		—		(1,837)		—		(918)
Bank overdrafts	1,622		—		663		—		2,285
Net cash provided by (used in) financing activities	(11,131)		144,867		(1,267)		34		132,503
Net increase (decrease) in cash and cash equivalents	102		(104)		(5,838)		—		(5,840)
Cash and cash equivalents, beginning of period	403		208		5,841		—		6,452
Cash and cash equivalents, end of period	$	505	$	104	$	3	$	—	$	612

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

Management’s Discussion and Analysis (MD&A) provides you with an understanding of our operating results and financial condition by focusing on changes in certain key measures from year to year or period to period. MD&A is organized into these sections:

•General;

•Recent Developments;

•Business Outlook;

•Executive Summary;

•Financial Condition and Liquidity;

•New Accounting Pronouncements; and

•Results of Operations.

Please read the information in our most recent Annual Report on Form 10-K as part of your review of the information below and our unaudited condensed consolidated financial statements and related notes.

Unless otherwise indicated or required by the content, when used in this report the terms “company,” “Unit,” “us,” “our,” “we,” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers to Superior Pipeline Company, L.L.C. of which we presently own 50%.

General

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 Unit Petroleum Company (UPC). This segment explores, develops, acquires, and produces oil and natural gas properties for our own account.

•Contract Drilling – carried out by our subsidiary Unit Drilling Company (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 for third parties and for our own account. We presently own 50% of this subsidiary.

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

Recent Developments

Emergence From Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On May 22, 2020 (Petition Date), Unit and its wholly owned subsidiaries UDC, UPC, 8200 Unit, Unit Drilling Colombia, and Unit Drilling USA filed 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 the caption In re Unit Corporation, et al., Case No. 20-32740 (DRJ) (Chapter 11 Cases). During the pendency of the Chapter 11 Cases, the Debtors operated their business as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and under the provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

The Debtors filed a Chapter 11 plan of reorganization (including all exhibits and schedules, and as may be amended, supplemented, or modified from time to time, the Plan) and the related disclosure statement with the Bankruptcy Court on June 9, 2020. On August 6, 2020, the Bankruptcy Court entered the “Findings of Fact, Conclusions of Law, and Order (I) Approving the Disclosure Statement on a Final Basis and (II) Confirming the Debtors’ Amended Joint Chapter 11 Plan of Reorganization” [Docket No. 340] (Confirmation Order) confirming the Plan. On September 3, 2020 (Effective Date), the Debtors emerged from the Chapter 11 Cases. For more information regarding the Chapter 11 Cases and other related matters, please read Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.

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Going Concern

Fresh Start Accounting

In connection with emergence from the Chapter 11 Cases on the Effective Date, the company qualified for and adopted fresh start accounting in accordance with the provisions set forth in FASB Topic ASC 852 as (i) the reorganization value of the company’s assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor prior to emergence received less than 50% of the voting shares of the emerging entity. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements of the Successor will not be comparable to the financial statements prepared before the Effective Date.

Changes in Accounting Policies

On emergence from bankruptcy, the company elected to change the accounting policies related to depreciation of fixed assets of our Contract Drilling segment and the allocation of earnings and losses between Unit and its partners in Superior.

In regards to our Contract Drilling segment, as of emergence, the company elected to depreciate all drilling assets using the straight-line method over the useful lives of the assets ranging from four to ten years.

On emergence, the company also elected to begin allocating earnings and losses between Unit and the partners in Superior using the Hypothetical Liquidation at Book Value (HLBV) method of accounting.

Leadership Changes

On October 22, 2020, David T. Merrill stepped down as President, Chief Executive Officer and Director of the company. Philip B. Smith, the company’s Chairman, currently serves as the company’s President and Chief Executive Officer.

On October 22, 2020, Les Austin retired as Senior Vice President and Chief Financial Officer of the company. The company appointed Thomas D. Sell as Interim Chief Financial Officer.

On October 22, 2020, Frank Q. Young stepped down as Executive Vice President of UPC.

On October 22, 2020, David P. Dunham was promoted to the company’s Senior Vice President and Chief Operating Officer. He was serving as our Senior Vice President of Business Development immediately before the promotion.

On October 27, 2020, Mark E. Schell, then our Executive Vice President, Secretary and General Counsel, was appointed as Executive Vice President and Chief Strategy Officer.

On November 9, 2020, Chris Menefee was appointed as President of UDC.

On December 31, 2020, Don Hayes retired as Vice President and Chief Accounting Officer of the company. He was replaced by Thomas Sell, who also serves as our Interim Chief Financial Officer.

For further information on the above leadership changes, please see the company’s Current Reports on Form 8-K filed on October 27, 2020, November 2, 2020, November 12, 2020 and December 11, 2020.

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Delisting of Our Common Stock from the NYSE

On May 26, 2020, trading in our common stock on the New York Stock Exchange (NYSE) was suspended because of the Debtors’ filing of the Chapter 11 Cases. Effective May 27, 2020, trades in our common stock began being quoted on the OTC Pink Marketplace. On June 10, 2020, the NYSE filed a Form 25 to delist our common stock and deregister it under Section 12(b) of the Securities Exchange Act of 1934, as amended (Exchange Act). On the Debtors’ emergence from the Chapter 11 Cases, the shares of Predecessor common stock outstanding immediately before the Effective Date were cancelled.

Business Outlook

Post-Emergence Strategy

Our post-emergence strategy is focused on value accretion through generation of free cash flows, repayment of debt, and selective investment in each business segment. Investments are expected to be funded using free cash flows from operations, proceeds from divestments of non-core assets, and available capacity under the Exit credit agreement, all subject to the various terms and conditions of the Exit credit agreement as referenced in Note 9 – Long-Term Debt and Other Long-Term Liabilities.

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

In our contract drilling segment we plan to focus on utilization of our BOSS drilling rigs, as well as upgrades to certain of our SCR drilling rigs. We also plan to continue seeking opportunities to divest non-core, idle drilling equipment.

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

COVID-19 Pandemic and Commodity Price Environment

As discussed in other parts of this report, among other things, our success depends, to a large degree, on the prices we receive for our oil and natural gas production, the demand for oil, natural gas, and NGLs, and the demand for our drilling rigs which influences the amounts we can charge for those drilling rigs. While our operations are all within the United States, events outside the United States affect us and our industry.

We are continuously monitoring the current and potential impacts of the COVID-19 pandemic on our business. This includes how it has and may continue to impact our operations, financial results, liquidity, customers, employees, and vendors. In response to the pandemic, we have reduced capital expenditures and implemented various measures to ensure we are conducting our business in a safe and secure manner. COVID-19 and the response of governments throughout the world to contain the pandemic have contributed to an economic downturn, reduced demand for oil and natural gas, and together with a price war between Saudi Arabia and Russia, depressed oil and natural gas prices to historically low levels. In April, the Organization of the Petroleum Exporting Countries (OPEC), Russia and certain other oil producing states (commonly referred to as OPEC Plus) agreed to cut oil production by 9.7 million barrels per day in May and June 2020, however, in July, they agreed to increase production by 1.6 million barrels per day starting in August 2020. With the combined effects of the increased production levels earlier in 2020, the recent increase in production and the reduction in demand caused by COVID-19, the global oil and natural gas supply and demand imbalance persists and continues to have a significant adverse effect on the oil and gas industry.

During the last three years, commodity prices have been volatile. Our oil and natural gas segment used two to three drilling rigs throughout 2017. With improved commodity prices during the first quarter of 2018, our oil and natural gas segment put four of our drilling rigs to work and increased the number to six drilling rigs for a brief period during the third quarter of 2018. We reduced our operated rig count in the fourth quarter of 2018 and the first quarter of 2019 before getting as high as six drilling rigs again in the second quarter of 2019. Due to declining prices we shut down our drilling program in July 2019 and used no drilling rigs the remainder of 2019 or the first nine months of 2020.

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The following chart reflects the significant fluctuations in the prices for oil and natural gas:

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

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

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Executive Summary

Oil and Natural Gas

Third quarter 2020 production from our oil and natural gas segment was 2,858,000 barrels of oil equivalent (Boe), a decrease of 5% from the second quarter of 2020 and a decrease of 35% from the third quarter of 2019. The decreases came from fewer net wells being drilled in the nine months ended September 30, 2020 to replace declines in existing drilled wells.

Third quarter 2020 oil and natural gas revenues increased 54% over the second quarter of 2020 and decreased 47% from the third quarter of 2019. The increase over the second quarter of 2020 was primarily due to an increase in commodity prices partially offset by a decrease in production. The decrease from the third quarter of 2019 was primarily from a decrease in commodity prices and production.

Our oil prices for the third quarter of 2020 increased 81% over the second quarter of 2020 and decreased 33% from the third quarter of 2019. Our NGLs prices increased 99% over the second quarter of 2020 and decreased 4% from the third quarter of 2019. Our natural gas prices increased 19% over the second quarter of 2020 and decreased 30% from the third quarter of 2019.

Operating cost per Boe produced for the third quarter of 2020 decreased 67% from the second quarter of 2020 and decreased 4% from the third quarter of 2019. The decreases were primarily due to the estimated $45.0 million litigation accrual in the second quarter of 2020.

At September 30, 2020, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Oct'20 - Dec'20

Natural gas - basis swap

30,000 MMBtu/day

$(0.275)

NGPL TEXOK

Oct'20 - Dec'20

Natural gas - basis swap

20,000 MMBtu/day

$(0.455)

PEPL

Jan'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$(0.215)

NGPL TEXOK

Oct'20 - Dec'20

Natural gas - swap

30,000 MMBtu/day

$2.753

IF - NYMEX (HH)

Jan'21 - Oct'21

Natural gas - swap

50,000 MMBtu/day

$2.818

IF - NYMEX (HH)

Nov'21 - Dec'21

Natural gas - swap

75,000 MMBtu/day

$2.880

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - swap

5,000 MMBtu/day

$2.605

IF - NYMEX (HH)

Jan'23 - Dec'23

Natural gas - swap

22,000 MMBtu/day

$2.456

IF - NYMEX (HH)

Oct'20 - Dec'20

Natural gas - collar

30,000 MMBtu/day

$2.50 - $2.80

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - collar

35,000 MMBtu/day

$2.50 - $2.68

IF - NYMEX (HH)

Oct'20 - Dec'20

Crude oil - swap

4,000 Bbl/day

$43.35

WTI - NYMEX

Jan'21 - Dec'21

Crude oil - swap

3,000 Bbl/day

$44.65

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

For the nine months ended September 30, 2020, we participated in the completion of 27 gross wells (6.16 net wells) drilled by other operators. We did not participate in the completion of any wells during the third quarter of 2020. In the fourth quarter, we plan to participate in the completion of one gross well drilled by another operator.

Contract Drilling

The average number of drilling rigs we operated in the third quarter of 2020 was 5.1 compared to 9.1 and 20.4 in the second quarter of 2020 and the third quarter of 2019, respectively. As of September 30, 2020, six of our drilling rigs were operating and two rigs were under stand-by contracts.

Revenue for the third quarter of 2020 decreased 59% from the second quarter of 2020 and decreased 68% from the third quarter of 2019. The decreases were primarily due to less drilling rigs operating.

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Dayrates for the third quarter of 2020 averaged $16,904, an 8% decrease from the second quarter of 2020 and a 12% decrease from the third quarter of 2019. The decreases were both primarily due to less drilling rigs operating.

Operating costs for the third quarter of 2020 decreased 60% from the second quarter of 2020 and decreased 71% from the third quarter of 2019. The decreases were both primarily due to less drilling rigs operating.

We have five term drilling contracts with original terms ranging from six months to two years that are up for renewal after 2020. Term contracts may contain a fixed rate during the contract or provide for rate adjustments within a specific range from the existing rate. Some operators who had signed term contracts have opted to release the drilling rig early and pay an early termination penalty for the remaining term of the contract.

Six of our 14 existing BOSS drilling rigs are under contract.

For 2020, we do not currently have an approved capital plan for this segment. Any capital expenditures incurred would be within anticipated cash flows.

Mid-Stream

Third quarter 2020 liquids sold per day decreased 2% from the second quarter of 2020 and increased 9% over the third quarter of 2019, respectively. The decrease from the second quarter of 2020 was due to lower purchased volumes due to fewer wells connected to our processing systems. The increase over the third quarter of 2019 was due to operating in ethane rejection for most of the third quarter of 2019 which resulted in lower amounts of liquids available for sale. For the third quarter of 2020, gas processed per day decreased 5% from the second quarter of 2020 and decreased 12% from the third quarter of 2019. The decreases were primarily due to declining volumes and fewer new well connects on our processing systems partially offset by increased gathered volume from the Cashion system due to the acquisition at the end of 2019. For the third quarter of 2020, gas gathered per day decreased 12% from the second quarter of 2020 and decreased 17% from the third quarter of 2019, respectively. These decreases were due to declining volumes from most of our major systems and fewer well connects partially offset by increased gathered volume from the Cashion system due to the acquisition at the end of 2019.

NGLs prices in the third quarter of 2020 increased 45% over the prices received in the second quarter of 2020 and decreased 7% from the prices received in the third quarter of 2019. Because certain contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts, under which we receive a share of the proceeds from the sale of the NGLs, our revenues from those commodity-based contracts fluctuate based on the price of NGLs.

Total operating cost for our mid-stream segment for the third quarter of 2020 increased 22% over the second quarter of 2020 and decreased 3% from the third quarter of 2019. The increase over the second quarter of 2020 was primarily due to higher purchase prices. The decrease from the third quarter of 2019 was primarily due to lower purchases prices along with less purchased volumes.

At the Cashion processing facility in central Oklahoma, total throughput volume for the third quarter of 2020 averaged approximately 75.5 MMcf per day and total production of natural gas liquids averaged approximately 354,000 gallons per day. Through the first nine months of 2020, we continued to connect new wells to this system for third party producers. Since the first of this year, we connected 14 new wells to this system from producers in the area. The acquired mid-continent production that was purchased at the end of 2019 is being processed at our Reeding facility on our Cashion system. Additionally, we are delivering the Perkins facility production to the Cashion Reeding facility. The total processing capacity on the Cashion system is 105 MMcf per day.

In the Appalachian region at the Pittsburgh Mills gathering system, average gathered volume for the third quarter of 2020 was 150.8 MMcf per day while the average gathered volume for second quarter of 2020 was approximately 181.8 MMcf per day as the Bakerstown infill wells continue to decline. During the third quarter of 2020, we did not add any new wells to this system.

At the Hemphill processing facility located in the Texas panhandle, average total throughput volume for the third quarter of 2020 was 50.1 MMcf per day and total production of natural gas liquids averaged approximately 187,000 gallons per day. We did not connect any new wells to this system in the third quarter of 2020. At this time there are no active rigs in the area and we did not have any new well connects the rest of this year.

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third quarter of 2020, we did not connect any new wells to this system. We did not connect any new wells to this system the rest of this year.

Anticipated 2020 capital expenditures for this segment will be approximately $11.0 million, an 83% decrease from 2019.

Financial Condition and Liquidity

Summary

Our financial condition and liquidity depend on the cash flow from our operations and borrowings under our credit agreements. Our cash flow is based primarily on:

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

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

•the demand for and the dayrates we receive for our drilling rigs; and

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

Our completion of the Chapter 11 Cases has allowed us to significantly reduce our level of indebtedness and our future cash interest obligations. We currently expect that cash and cash equivalents, cash generated from operations, and our available funds under the Exit credit agreement are adequate to cover our liquidity requirements for at least the next 12 months.

Below is a summary of certain financial information for the periods indicated (in thousands):


	Successor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
Net cash provided by operating activities	$	9,674	$	44,956	$	219,450
Net cash used in investing activities	(1,022)		(20,139)		(357,793)
Net cash provided by (used in) financing activities	(4,350)		7,552		132,503
Net increase (decrease) in cash, restricted cash, and cash equivalents	$	4,302	$	32,369	$	(5,840)

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 quantity of oil, NGLs, and natural gas we produce, settlements of derivative contracts, and third-party demand for our drilling rigs and mid-stream services and the rates we obtain for those services. Our cash flows from operating activities are also affected by changes in working capital.

Net cash provided by operating activities in the first nine months of 2020 decreased by $164.8 million as compared to the first nine months of 2019. The decrease was primarily due to lower revenues due to lower commodity prices and lower drilling rig utilization partially offset by an increase in changes in operating assets and liabilities related to the timing of cash receipts and disbursements.

Cash Flows from Investing Activities

We have historically dedicated a substantial part of our capital budget to the exploration for and production of oil, NGLs, and natural gas. Those expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells. As previously noted, for 2020 we greatly restricted our capital spending in this segment.

Net cash used in investing activities decreased by $336.6 million for the first nine months of 2020 compared to the first nine months of 2019. The change was due primarily to a decrease in capital expenditures due to decrease in operated wells drilled and a decrease in oil and gas property acquisitions partially offset by a decrease in the proceeds received from the disposition of assets. See additional information on capital expenditures below under Capital Requirements.

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Cash Flows from Financing Activities

Net cash provided by (used in) financing activities decreased by $129.3 million for the first nine months of 2020 compared to the first nine months of 2019. The decrease was primarily due to a decrease in the net borrowings under our credit agreements and a decrease in bank overdrafts.

At September 30, 2020, we had unrestricted cash and cash equivalents totaling $29.8 million and had borrowed $132.0 million and $12.0 million of the amounts available under the Unit Exit credit agreement and Superior credit agreement, respectively.

Below, we summarize certain financial information as of September 30, 2020 and 2019:


	Successor		Predecessor
	September 30,		September 30,		% Change
	2020		2019
	(In thousands except percentages)
Working capital	$	21,624	$	(56,116)	139	%
Current portion of long-term debt	$	400	$	—	—	%
Long-term debt (1)	$	143,600	$	784,352	(82)	%
Shareholders’ equity attributable to Unit Corporation	$	188,364	$	1,188,747	(84)	%

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1.In 2019, long-term debt is net of unamortized discount and debt issuance costs.

Working Capital

Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative activity. We had positive working capital of $21.6 million as of September 30, 2020 and negative working capital of $56.1 million as of September 30, 2019. The increase in working capital is primarily due to more cash and cash equivalents and lower accounts payable and accrued liabilities due to the settlement of the liabilities subject to compromise partially offset by lower accounts receivable. The Superior credit agreement is used primarily for working capital and capital expenditures and the Exit credit agreement facility is used to primarily for working capital and has limitations on how much can be spent for capital expenditures. At September 30, 2020, we had borrowed $131.6 million and $12.0 million under the Unit Exit credit agreement and Superior credit agreement, respectively. The effect of our derivative contracts increased working capital by $1.3 million as of September 30, 2020 and increased working capital by $6.0 million as of September 30, 2019.

Long-Term Debt

Unit's Exit credit agreement facility is primarily used for working capital purposes as it limits the amount that can be borrowed for capital expenditures. These limitations will result in limited future capital projects utilizing the Exit credit facility. The Exit credit facility also requires the company to use proceeds from the disposition of certain assets to repay amounts outstanding. This aligns with our free cash flow business model, enabling the company to maintain reduced leverage through debt reduction in future periods.

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This table summarizes certain operating information:


	Successor		Predecessor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31 2020		September 30, 2019		% Change (1)
Oil and Natural Gas:
Oil production (MBbls)	167		1,562		2,341		(26)	%
NGLs production (MBbls)	273		2,399		3,657		(27)	%
Natural gas production (MMcf)	2,849		26,563		40,021		(27)	%
Equivalent barrels (MBoe)	914		8,388		12,668		(27)	%
Average oil price per barrel received	$	28.11	$	31.98	$	57.55	(45)	%
Average oil price per barrel received excluding derivatives	$	36.94	$	35.14	$	55.28	(36)	%
Average NGLs price per barrel received	$	7.47	$	4.83	$	12.21	(58)	%
Average NGLs price per barrel received excluding derivatives	$	7.47	$	4.83	$	12.21	(58)	%
Average natural gas price per Mcf received	$	1.72	$	1.14	$	2.07	(42)	%
Average natural gas price per Mcf received excluding derivatives	$	1.70	$	1.11	$	1.90	(38)	%



Contract Drilling:
Average number of our drilling rigs in use during the period	6.0		11.5		26.8		(59)	%
Total drilling rigs available for service at the end of the period	58		58		57		2	%
Average dayrate	$	17,361	$	18,911	$	18,635	1	%
Mid-Stream:
Gas gathered—Mcf/day	345,460		388,506		447,989		(13)	%
Gas processed—Mcf/day	145,263		158,031		165,061		(5)	%
Gas liquids sold—gallons/day	473,371		612,301		644,601		(7)	%
Number of natural gas gathering systems	18		18		21		(14)	%
Number of processing plants	11		11		12		(8)	%

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1.This is a comparison between the sum of the one month ended Successor period and the eight month ended Predecessor period in 2020 and the nine months ended 2019.

Oil and Natural Gas Operations

Any significant change in oil, NGLs, or natural gas prices has a material effect on our revenues, cash flow, and the value of our oil, NGLs, and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances, and by worldwide oil price levels. Global oil market developments primarily influence domestic oil prices. These factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive.

Based on our first nine months of 2020 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of derivatives, would cause a corresponding $279,000 per month ($3.4 million annualized) change in our pre-tax operating cash flow. The average price we received for our natural gas production, including the effect of derivatives, during the first nine months of 2020 was $1.20 compared to $2.07 for the first nine months of 2019. Based on our first nine months of 2020 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $160,000 per month ($1.9 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 derivatives, would have a $264,000 per month ($3.2 million annualized) change in our pre-tax operating cash flow. In the first nine months of 2020, our average oil price per barrel received, including the effect of derivatives, was $31.61 compared with an average oil price, including the effect of derivatives, of $57.55 in the first nine

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months of 2019 and our first nine months of 2020 average NGLs price per barrel received, including the effect of derivatives was $5.10 compared with an average NGLs price per barrel of $12.21 in the first nine months of 2019.

Our natural gas production is sold to intrastate and interstate pipelines and to independent marketing firms and gatherers under contracts with terms ranging from one month to five years. Our oil production is sold to independent marketing firms generally under six-month contracts.

Successor Impairment

As of September 1, 2020, we adopted fresh start accounting and adjusted our assets to fair value. Under full cost accounting rules we must review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is called the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the most recent unescalated historical 12-month average price of our oil, NGLs, and natural gas), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties in the costs being amortized, less related income taxes. If the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short while. Once incurred, a write-down of oil and natural gas properties is not reversible.

We also anticipate a non-cash ceiling test write-down in the fourth quarter of 2020 of our proved reserves, again due to the use of historical 12-month average commodity prices for the ceiling test. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at September 30, 2020, and only adjust the 12-month average price as of December 2020, our forward looking expectation is that we would recognize an impairment in the range of $30 million to $35 million pre-tax in the fourth quarter of 2020. Given the uncertainty associated with the factors used in calculating our estimate of our future period ceiling test write-down, these estimates should not necessarily be construed as indicative of our future development plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination.

Predecessor Impairments

During the first quarter of 2020, we determined that, because of the increased uncertainty in our business, our undeveloped acreage would not be fully developed and thus certain unproved oil and gas properties carrying values were not recoverable resulting in an impairment of $226.5 million, which had a corresponding increase to our depletion base and contributed to our full cost ceiling impairment recorded during the first quarter of 2020. We recorded a non-cash full cost ceiling test write-down of $267.8 million pre-tax in the first quarter of 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. The 12-month average commodity prices decreased further, resulting in non-cash ceiling test write-downs of $109.3 million in the second quarter and $16.6 million in the two months ended August 31, 2020. In the third quarter of 2019, we determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $50.0 million of cost being added to the total of our capitalized costs being amortized in the third quarter of 2019. We incurred a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax) in the third quarter of 2019.

In addition to the impairment evaluations of our proved and unproved oil and gas properties in the first quarter of 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast of asset utilization, we determined certain assets were no longer expected to be used and wrote off certain salt water disposal assets that we now consider abandoned. We recorded expense of $17.6 million related to the write-down of our salt water disposal assets in the first quarter of 2020.

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Contract Drilling Operations

Many factors influence the number of drilling rigs we are able to put to work and the costs and revenues associated with that work. These factors include the demand for drilling rigs in our areas of operation, competition from other drilling contractors, the prevailing prices for oil, NGLs, and natural gas, availability and cost of labor to run our drilling rigs, and our ability to supply the equipment needed.

Most of our working drilling rigs are drilling horizontal or directional wells for oil and NGLs. The continuous fluctuations in commodity prices changes the demand for drilling rigs. These factors ultimately affect the demand and mix of the drilling rigs used by our customers. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates. For the first nine months of 2020, our average dayrate was $18,814 per day compared to $18,635 per day for the first nine months of 2019. The average number of our drilling rigs used in the first nine months of 2020 was 10.9 drilling rigs compared with 26.8 drilling rigs in the first nine months of 2019. Based on the average utilization of our drilling rigs during the first nine months of 2020, a $100 per day change in dayrates has a $1,090 per day ($0.4 million annualized) change in our pre-tax operating cash flow.

Our contract drilling segment provides drilling services for our exploration and production segment. Some of the drilling services we perform on our properties are, depending on the timing of those services, deemed associated with acquiring an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in our income statements, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $15.8 million for the first nine months of 2019, from our contract drilling segment and eliminated the associated operating expense of $14.2 million during the first nine months of 2019, yielding $1.6 million during the first nine months of 2019, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue in our contract drilling segment for the first nine months of 2020.

There were no impairment triggering events identified in the one month Successor period ended September 30, 2020 for our contract drilling assets.

Predecessor Impairments

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

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

Mid-Stream Operations

Our mid-stream segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates three natural gas treatment plants, 11 processing plants, 18 gathering systems, and approximately 2,090 miles of pipeline. It operates in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. Besides serving third parties, this segment also enhances our ability to gather and market our own natural gas and NGLs and serving as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first nine months of 2020 and 2019, our mid-stream operations purchased $13.9 million and $31.8 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $3.1 million and $5.4 million, respectively. Intercompany revenue from services and purchases of production between this business segment and our oil and natural gas segment has been eliminated in our unaudited condensed consolidated financial statements.

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This segment gathered an average of 383,793 Mcf per day in the first nine months of 2020 compared to 447,989 Mcf per day in the first nine months of 2019. It processed an average of 156,633 Mcf per day in the first nine months of 2020 compared to 165,061 Mcf per day in the first nine months of 2019. The NGLs sold was 597,090 gallons per day in the first nine months of 2020 compared to 644,601 gallons per day in the first nine months of 2019. Gas gathered volumes per day in the first nine months of 2020 decreased 14% compared to the first nine months of 2019 primarily due to declining volumes from most of our major systems partially offset by higher volumes on our Cashion system, due to new well connects along with the new acquisition at the end of 2019. Gas processed volumes for the first nine months of 2020 decreased 5% compared to the first nine months of 2019 due to connecting fewer wells to our processing systems along with declining volumes on most major systems, which was partially offset by added volumes from new well connects and from the new acquisition at our Cashion processing facility. NGLs sold in the first nine months of 2020 decreased 7% compared to the first nine months of 2019 due to declining volumes on several major processing systems and operating several of our processing facilities in ethane rejection mode.

There were no impairment triggering events identified in the one month Successor period ended September 30, 2020 for our gas gathering and processing assets.

Predecessor Impairments

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

Our Credit Agreements and Predecessor Senior Subordinated Notes

The Exit credit agreement requires the company to comply with certain financial ratios, including a covenant that the company will not permit the Net Leverage Ratio (as defined in the Exit credit agreement) as of the last day of the fiscal quarters ending (i) December 31, 2020 and March 31, 2021, to be greater than 4.00 to 1.00, (ii) June 30, 2021, September 30, 2021, December 31, 2021, March 31, 2022, and June 30, 2022, to be greater than 3.75 to 1.00, and (iii) September 30, 2022 and any fiscal quarter thereafter, to be greater than 3.50 to 1.00. In addition, beginning with the fiscal quarter ending December 31, 2020, the company may not (a) permit the Current Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 0.50 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, restrict certain asset sales and the related use of proceeds, and require certain hedging activities. The Exit credit agreement further requires that the company provide Quarterly Financial Statements within 45 days after the end of each of the first three quarters of each fiscal year and Annual Financial Statements within 90 days after the end of each fiscal year. For the quarter ended September 30, 2020, the syndicate banks allowed for an extension.

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Superior Credit Agreement. On May 10, 2018, Superior signed a five-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions (Superior credit agreement). The amounts borrowed under the Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) the Thirty-Day LIBOR Rate (as defined in the Superior credit agreement plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by, among other things, 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

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accurately reflects the rate available to the Administrative Agent in the London Interbank Market, the Administrative Agent may select a replacement index.

The borrowings under the Superior credit agreement will fund capital expenditures and acquisitions and provide general working capital and letters of credit for Superior.

Superior's credit agreement is not guaranteed by Unit. Superior and its subsidiaries were not Debtors in the Chapter 11 Cases.

The lenders under the Superior credit agreement and their respective participation interests are:


Lender	Participation Interest
BOK (BOKF, NA, dba Bank of Oklahoma)	17.50	%
Compass Bank	17.50	%
BMO Harris Financing, Inc.	13.75	%
Toronto Dominion (New York), LLC	13.75	%
Bank of America, N.A.	10.00	%
Branch Banking and Trust Company	10.00	%
Comerica Bank	10.00	%
Canadian Imperial Bank of Commerce	7.50	%
	100.00	%

Predecessor 6.625% Senior Subordinated Notes. The Predecessor's Notes were issued under an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for issuing the Notes.

As a result of Unit's emergence from bankruptcy, the Notes were cancelled and the Predecessor's liability thereunder discharged as of the Effective Date, and the holders of the Notes were issued approximately 10.5 million shares New Common Stock.

Predecessor DIP Credit Agreement. As contemplated by the RSA, the company and the other Debtors entered into a Superpriority Senior Secured Debtor-in-Possession Credit Agreement dated May 27, 2020 ( DIP credit agreement), by and among the Debtors, the RBL Lenders (in such capacity, the DIP Lenders), and BOKF, NA dba Bank of Oklahoma, as administrative agent, under which the DIP Lenders agreed to provide the company with the $36.0 million multiple-draw loan facility (DIP credit facility). The Bankruptcy Court entered an interim order on May 26, 2020 approving the DIP credit facility, permitting the Debtors to borrow up to $18.0 million on an interim basis. On June 19, 2020, the Bankruptcy Court granted final approval of the DIP credit facility.

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of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code and (v) the date of termination of the DIP Lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP credit facility under and subject to the DIP credit agreement and the Bankruptcy Court’s orders.

On the Effective Date, the DIP credit agreement was paid in full and terminated. On the Effective Date, each holder of an allowed claim under the DIP credit facility received its pro rata share of revolving loans, term loans and letter-of-credit participations under the exit facility. In addition, each such holder was issued on the Effective Date (or promptly following the Effective Date) its pro rata share of an equity fee under the exit facility equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and upon exercise of the Warrants).

For further information about the DIP credit agreement, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.

Warrants

Each holder of the company’s common stock outstanding before the Effective Date (Predecessor Common Stock) that did not opt out of the release under the Plan, is entitled to receive its pro rata share of seven-year warrants (Warrants) to purchase an aggregate of 12.5% of the shares of New Common Stock, at an aggregate exercise price equal to the $650.0 million principal amount of the Notes plus interest thereon to the May 15, 2021 maturity date of the Notes. On the Effective Date, the company entered into a Warrant Agreement (Warrant Agreement) with American Stock Transfer & Trust Company, LLC. The Warrants will expire on the earliest of (i) September 3, 2027, (ii) the consummation of a Cash Sale (as defined in the Warrant Agreement) or (iii) the consummation of a liquidation, dissolutions or winding up of the company (such earliest date, the Expiration Date). Each Warrant that is not exercised on or before the Expiration Date will expire, and all rights under such Warrant and the Warrant Agreement will cease on the Expiration Date. On December 21, 2020, the company issued approximately 1.8 million Warrants to the holders of the Predecessor Common Stock that did not opt out of the releases under the Plan and owned their shares of Predecessor Common Stock in street name through the facilities of the DTC. The company expects to issue approximately 79,000 more Warrants to the holders of the Predecessor Common Stock that did not opt out of the releases under the Plan and owned their shares through direct registration with the company’s transfer agent (Direct Registration). Under the Plan, additional Warrants will be issued in book-entry form through the facilities of the DTC, and each holder owning shares of Predecessor Common Stock through Direct Registration must provide that holder’s brokerage account information to the company to receive holder’s distribution of Warrants. Holders of shares of the Predecessor Common Stock that owned shares through Direct Registration should contact Prime Clerk, LLC at (877) 720-6581 (Toll Free) or (646) 979-4412 (Local) to obtain the forms necessary to receive their distribution. Any distribution not made will be deemed forfeited at the first anniversary of the Effective Date.

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 under the circumstances which provide us with flexibility in deciding when and if to incur these costs. We participated in the completion of 27 gross wells (6.16 net wells) drilled by other operators in the first nine months of 2020 compared to 89 gross wells (28.59 net wells) drilled by Unit and other operators in which we participated in the first nine months of 2019.

Capital expenditures for oil and gas properties on the full cost method for the first nine months of 2020 by this segment, excluding $0.4 million for acquisitions, totaled $10.3 million. Capital expenditures for the first nine months of 2019, excluding $3.3 million for acquisitions, totaled $246.0 million.

For 2020, we did not drill any company operated wells.

Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. During the first quarter of 2019, we completed construction and placed into service our 12th and 13th BOSS drilling rigs. One was delivered to an existing third-party operator in Wyoming. Two additional BOSS drilling rigs under contract with the same customer were also extended. The other BOSS drilling rig was delivered to a new customer in the Permian Basin. This was following an early termination by the original third-party operator before the drilling rig’s completion. Our 14th BOSS drilling rig was completed and placed into service in December of 2019 for a third-party under a long term contract. During the second quarter of 2019, two existing BOSS drilling rig contracts working for the same operator were also extended.

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We have no commitments or plans to build any additional BOSS drilling rigs in 2020.

For 2020, we do not currently have an approved capital plan for this segment. Capital expenditures incurred would be within anticipated cash flows. We have spent $4.0 million for capital expenditures during the first nine months of 2020, compared to $36.6 million for capital expenditures during the first nine months of 2019.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. At the Cashion processing facility in central Oklahoma, total throughput volume for the third quarter of 2020 averaged approximately 75.5 MMcf per day and total production of natural gas liquids averaged approximately 354,000 gallons per day. Through the first nine months of 2020, we continued to connect new wells to this system for third party producers. Since the first of this year, we connected 14 new wells to this system from producers in the area. The acquired mid-continent production that was purchased at the end of 2019 is being processed at our Reeding facility on our Cashion system. Additionally, we are delivering the Perkins facility production to the Cashion Reeding facility. The total processing capacity on the Cashion system is 105 MMcf per day.

At the Segno gathering system located in East Texas, the average throughput volume for the third quarter of 2020 decreased to 35.1 MMcf per day due to declining production volume along with no new drilling activity in the area. During the third quarter of 2020, we did not connect any new wells to this system. We did not connect any new wells to this system the rest of this year.

During the first nine months of 2020, our mid-stream segment incurred $10.2 million in capital expenditures as compared to $41.4 million in the first nine months of 2019. For 2020, our estimated capital expenditures is approximately $11.0 million.

Contractual Commitments

At September 30, 2020, we had certain contractual obligations including:


	Payments Due by Period
	Total		Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years
	(In thousands)
Long-term debt (1)	$	174,182	$	9,282	$	29,374	$	135,526	$	—
Operating leases (2)	6,416		3,985		2,355		21		55
Finance lease interest and maintenance (3)	1,051		1,051		—		—		—
Firm transportation commitments (4)	1,702		1,216		486		—		—
Total contractual obligations	$	183,351	$	15,534	$	32,215	$	135,547	$	55

_______________________

1.See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Unit Exit Facility and includes interest calculated using our September 30, 2020 interest rates of 6.6% for our Unit Exit Facility and 2.1% for our Superior credit agreement. The Unit Exit Facility has a maturity date of March 1, 2024 and outstanding balance as of September 30, 2020 of $132.0 million ($0.4 million is reflected as a current liability in our consolidated balance sheet). Our Superior credit agreement has a maturity date of May 10, 2023 and an outstanding balance of $12.0 million as of September 30, 2020.

2.We lease certain office space, land and equipment, including pipeline equipment and office equipment under the terms of operating leases under ASC 842 expiring through March 2031. We also have short-term lease commitments of $1.4 million. This is lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; and Pinedale, Wyoming under the terms of operating leases expiring through June 2021. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.

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3.Maintenance and interest payments are included in our finance lease agreements. The finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining are $1.0 million and $0.1 million, respectively.

4.We have firm transportation commitments to transport our natural gas from various systems for approximately $1.2 million over the next twelve months and $0.5 million for the two years thereafter.

During the second quarter of 2018, as part of the Superior transaction, we entered into a contractual obligation committing us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. For each dollar of the $150.0 million we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our ownership interest in our consolidated mid-stream subsidiary. At September 30, 2020, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.6 million. Total spent towards the $150.0 million as of September 30, 2020 was $24.8 million.

At September 30, 2020, we also had the following commitments and contingencies that could create, increase, or accelerate our liabilities:


	Estimated Amount of Commitment Expiration Per Period
Other Commitments	Total Accrued		Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years
	(In thousands)
Deferred compensation plan (1)	$	—	$	—	$	—	$	—	$	—
Separation benefit plans (2)	$	4,536	$	1,374	Unknown		Unknown		Unknown
Asset retirement liability (3)	$	24,922	$	2,186	$	3,387	$	3,286	$	16,063
Gas balancing liability (4)	$	3,824	Unknown		Unknown		Unknown		Unknown
Workers’ compensation liability (5)	$	11,664	$	1,713	Unknown		Unknown		Unknown
Finance lease obligations (6)	$	4,272	$	4,272	$	—	$	—	$	—
Contract liability (7)	$	4,899	$	2,779	$	2,089	$	12	$	19
Other long-term liabilities (8)	$	1,997	$	—	$	1,997	$	—	$	—

_______________________

1.We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death, or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets, at the time of deferral. As of September 30, 2020, this plan has been paid out to plan participants.

2.As of the Effective Date, the Board adopted (i) the Amended and Restated Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Separation Benefit Plan), (ii) the Amended and Restated Special Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Special Separation Benefit Plan) and (iii) the Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (New Separation Benefit Plan). In accordance with the Plan, the Amended Separation Benefit Plan and the Amended Special Separation Benefit Plan allow former employees or retained employees with vested severance benefits under either plan to receive certain cash payments in full satisfaction for their allowed separation claim under the Chapter 11 Cases. In accordance with the Plan, the New Separation Benefit Plan is a comprehensive severance plan for retained employees, including retained employees whose severance did not already vest under the Amended Separation Benefit Plan or the Amended Special Separation Benefit Plan. The New Separation Benefit Plan provides that eligible employees will be entitled to two weeks of severance pay per year of service, with a minimum of four weeks and a maximum of 13 weeks of severance pay.

3.When a well is drilled or acquired, under ASC 410 “Accounting for Asset Retirement Obligations,” we record the discounted fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).

4.We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners to recover their under-production from future production volumes.

5.We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment.

6.The amount includes commitments under finance lease arrangements for compressors in Superior.

7.We have recorded a liability related to the timing of revenue recognized on certain demand fees for Superior.

8.Due to the issuance of the Coronavirus Aid, Relief, and Economic Security Act (CARES Act), we have deferred our FICA tax payment.

Derivative Activities

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

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Commodity Derivatives. Our commodity derivatives are intended to reduce our exposure to price volatility and manage price risks. Our decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our view of current and future market conditions. At September 30, 2020, based on our third quarter 2020 average daily production, the approximated percentages of our production under derivative contracts are as follows:


	2020		2021		2022		2023
Daily oil production	72	%	54	%	41	%	23	%
Daily natural gas production	61	%	50	%	40	%	22	%

With respect to the commodities subject to derivative contracts, those contracts serve to limit the risk of adverse downward price movements. However, they also limit increases in future revenues that would otherwise result from price movements above the contracted prices.

The use of derivative transactions carries with it the risk that the counterparties may not be able to meet their financial obligations under the transactions. Based on our September 30, 2020 evaluation, we believe the risk of non-performance by our counterparties is not material. At September 30, 2020, the fair values of the net assets we had with each of the counterparties to our commodity derivative transactions are as follows:


	September 30, 2020
	(In thousands)
Bank of Oklahoma	$	726
Bank of America	(196)
Bank of Montreal	(1,026)
Total net liabilities	$	(496)

If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets. At September 30, 2020, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $2.4 million and current derivative liabilities of $1.1 million and non-current derivative liabilities of $1.7 million. At December 31, 2019, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $0.6 million and non-current derivative liabilities of less than $0.1 million.

For our economic hedges any changes in their 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. These gains (losses) at September 30 are as follows:


	Successor		Predecessor		Predecessor
	One Month Ended		Two Months Ended		Three Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of ($1,418), ($3,552), and $6,515, respectively	$	3,939	$	(4,250)	$	4,237
	$	3,939	$	(4,250)	$	4,237

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	Successor		Predecessor		Predecessor
	One Month Ended		Eight Months Ended		Nine Months Ended
	September 30, 2020		August 31, 2020		September 30, 2019
	(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of ($1,418), ($4,244), and $11,829, respectively	$	3,939	$	(10,704)	$	5,232
	$	3,939	$	(10,704)	$	5,232

Stock and Incentive Compensation

During the first nine months of 2020, we did not grant any awards. We recognized compensation expense of $6.1 million for all of our prior restricted stock awards including the acceleration of the unrecorded stock compensation expense. We did not capitalize any compensation cost to oil and natural gas properties since we are currently not drilling.

During the first nine months of 2019, we granted awards covering 1,424,027 shares of restricted stock. These awards had an estimated fair value as of their grant date of $22.6 million. Compensation expense will be recognized over the three-year vesting periods, and during the nine months of 2019, we recognized $5.9 million in compensation expense and capitalized $1.0 million for these awards. During the first nine months of 2019, we recognized compensation expense of $13.0 million for all of our restricted stock and stock options and capitalized $2.0 million of compensation cost to oil and natural gas properties.

Insurance

We are self-insured for certain losses relating to workers’ compensation, general liability, control of well, and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to $1.0 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. There is no assurance that the insurance coverage we have will protect us against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums.

Oil and Natural Gas Limited Partnerships and Other Entity Relationships

We were the general partner of 13 oil and natural gas partnerships formed privately or publicly. Each partnership’s revenues and costs were shared under formulas set out in that partnership’s agreement. The partnerships repaid us for contract drilling, well supervision, and general and administrative expense. Related party transactions for contract drilling and well supervision fees were the related party’s share of such costs. These costs were billed the same as billings to unrelated third parties for similar services. General and administrative reimbursements consisted of direct general and administrative expense incurred on the related party’s behalf and indirect expenses assigned to the related parties. Allocations are based on the related party’s level of activity and were considered by us to be reasonable. Our proportionate share of assets, liabilities, and net income relating to the oil and natural gas partnerships is included in our unaudited condensed consolidated financial statements. The partnerships were terminated during the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest.

New Accounting Pronouncements

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apply the amendments prospectively through December 31, 2022. The company is currently evaluating the impact this may have on its consolidated financial statements.

Currently there are no accounting pronouncements that have been issued, but not yet adopted, that are expected to have a material impact on our consolidated financial statements or disclosures.

Adopted Standards

Measurement of Credit Losses on Financial Instruments (Topic 326). The FASB issued ASU 2016-13 which replaces current methods for evaluating impairment of financial instruments not measured at fair value, including trade accounts receivable and certain debt securities, with a current expected credit loss model ("CECL"). The CECL model is expected to result in more timely recognition of credit losses. The amendment was effective for reporting periods after December 15, 2019. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures.

Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were removed or modified, and other disclosures were added. The amendment was effective for reporting periods beginning after December 15, 2019. Early adoption is permitted. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures.

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Results of Operations

Quarter Ended September 30, 2020 versus Quarter Ended September 30, 2019

Provided below is a comparison of selected operating and financial data after eliminations (in thousands unless otherwise specified):


	Successor			Predecessor			Predecessor
	One Month Ended			Two Months Ended			Three Months Ended			Percent Change (1)
	September 30, 2020			August 31, 2020			September 30, 2019
Total revenue	$	32,846		$	65,574		$	155,439		(37)	%
Net income (loss)	$	(6,736)		$	128,615		$	(207,789)		159	%
Net income (loss) attributable to non-controlling interest	$	2,232		$	73,484		$	(903)		NM
Net loss attributable to Unit Corporation	$	(8,968)		$	55,131		$	(206,886)		122	%

Oil and Natural Gas:
Revenue	$	13,643		$	27,961		$	78,045		(47)	%
Operating costs excluding depreciation, depletion, and amortization	$	6,674		$	15,488		$	35,364		(37)	%
Depreciation, depletion, and amortization	$	4,199		$	9,975		$	43,587		(67)	%
Impairment of oil and natural gas properties	$	13,237		$	16,572		$	169,806		(82)	%
Average oil price (Bbl)	$	28.11		$	29.59		$	56.62		(49)	%
Average NGLs price (Bbl)	$	7.47		$	8.53		$	8.50		(4)	%
Average natural gas price (Mcf)	$	1.72		$	1.07		$	1.83		(30)	%
Oil production (MBbls)	167			341			927			(45)	%
NGL production (MBbls)	273			572			1,240			(32)	%
Natural gas production (MMcf)	2,849			6,185			13,362			(32)	%
Depreciation, depletion, and amortization rate (Boe)	$	4.56		$	4.74		$	9.54		(52)	%

Contract Drilling:
Revenue	$	4,414		$	7,685		$	37,596		(68)	%
Operating costs excluding depreciation	$	2,989		$	5,410		28,796			(71)	%
Depreciation	$	526		$	853		$	12,845		(89)	%
Impairment of goodwill	$	—		$	—		$	62,809		(100)	%

Percentage of revenue from daywork contracts	100		%	100		%	100		%	—	%
Average number of drilling rigs in use	6.0			4.6			20.4			(75)	%
Average dayrate on daywork contracts	$	17,361		$	16,596		$	19,276		(12)	%

Mid-Stream:
Revenue	$	14,789		$	29,928		$	39,798		12	%
Operating costs excluding depreciation and amortization	$	9,852		$	17,822		$	28,493		(3)	%
Depreciation and amortization	$	2,658		$	6,750		$	11,847		(21)	%

Gas gathered--Mcf/day	345,460			363,465			428,573			(17)	%
Gas processed--Mcf/day	145,263			149,483			167,687			(12)	%
Gas liquids sold--gallons/day	473,371			699,647			572,852			9	%

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	Successor			Predecessor			Predecessor
	One Month Ended			Two Months Ended			Three Months Ended			Percent Change (1)
	September 30, 2020			August 31, 2020			September 30, 2019
Corporate and Other:
Loss on abandonment of assets	$	—		$	1,179		$	—		—	%
General and administrative expense	$	1,582		$	5,399		$	10,094		(31)	%
Other depreciation	$	84		$	341		$	1,935		(78)	%
Loss on disposition of assets	$	222		$	1,356		$	(231)		NM
Other income (expense):
Interest income	$	—		$	—		$	3		(100)	%
Interest expense, net	$	(826)		$	(1,959)		$	(9,537)		(71)	%
Reorganization costs, net	$	(1,155)		$	141,002		$	—		—	%
Gain (loss) on derivatives	$	3,939		$	(4,250)		$	4,237		(107)	%
Other	$	39		$	1,931		$	(622)		NM
Income tax benefit	$	—		$	(4,750)		$	(50,763)		91	%
Average interest rate	5.9		%	2.7		%	6.3		%	(41)	%
Average long-term debt outstanding	$	146,267		$	160,039		$	775,837		(80)	%

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1.This is a comparison between the sum of the one month ended Successor period and the two month ended Predecessor period in 2020 and the three month ended period in 2019. NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

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Oil and Natural Gas

Oil and natural gas revenues decreased $36.4 million or 47% in the third quarter of 2020 as compared to the third quarter of 2019 primarily due to lower commodity volumes. In the third quarter of 2020, as compared to the third quarter of 2019, oil production decreased 45%, natural gas production decreased 32%, and NGLs production decreased 32%. Including derivatives settled, average oil prices decreased 33% to $37.98 per barrel, average natural gas prices decreased 30% to $1.28 per Mcf, and NGLs prices decreased 4% to $8.19 per barrel.

Oil and natural gas operating costs decreased $13.2 million or 37% between the comparative third quarters of 2020 and 2019 primarily due to lower lease operating expenses (LOE), and gross production taxes.

Depreciation, depletion, and amortization (DD&A) decreased $29.4 million or 67% due primarily to a 52% decrease in the DD&A rate and a 35% decrease in equivalent production. The decrease in our DD&A rate in the third quarter of 2020 compared to the third quarter of 2019 resulted primarily from reduced net book value due to ceiling test write-downs.

For the one month period ending September 30, 2020, we recorded a non-cash ceiling test write-down of $13.2 million pre-tax. For the two month period ending August 31, 2020, we recorded a non-cash ceiling test write-down of $16.6 million pre-tax. During the third quarter of 2019, we recorded a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax).

Contract Drilling

Drilling revenues decreased $25.5 million or 68% in the third quarter of 2020 versus the third quarter of 2019. The decrease was due primarily to a 75% decrease in the average number of drilling rigs in use and a 12% decrease in the average dayrate. Average drilling rig utilization decreased from 20.4 drilling rigs in the third quarter of 2019 to 5.1 drilling rigs in the third quarter of 2020.

Drilling operating costs decreased $20.5 million or 71% between the comparative third quarters of 2020 and 2019. The decrease was due primarily to less drilling rigs operating. Contract drilling depreciation decreased $11.5 million or 89% in the third quarter of 2020 versus the third quarter of 2019 also due to less drilling rigs operating and from the lower depreciable net book value due to impairments in the first nine months of 2020.

Mid-Stream

Our mid-stream revenues increased $4.9 million or 12% in the third quarter of 2020 as compared to the third quarter of 2019 due primarily to recognizing a one-time shortfall fee from one of our producers partially offset by lower gas, NGLs, and condensate prices and volumes. Gas processed volumes per day decreased 12% between the comparative quarters primarily due to connecting fewer new wells and declining volumes on most of our major processing systems, partially offset by increased volumes from the Cashion system due to the acquisition at the end of 2019. Gas gathered volumes per day decreased 17% between the comparative quarters due to fewer new well connects and declining volumes from most of our major systems partially offset by higher volume on our Cashion system.

Operating costs decreased $0.8 million or 3% in the third quarter of 2020 compared to the third quarter of 2019 primarily due to lower purchase volumes and lower field operating expenses. Depreciation and amortization decreased $2.4 million, or 21%, primarily due to impairing the carrying value of several of our systems in the first quarter of 2020.

Loss on Abandonment of Assets

We recorded expense of $1.1 million related to the write-down of certain equipment in our drilling segment in the third quarter of 2020.

General and Administrative

Corporate general and administrative expenses decreased $3.1 million or 31% in the third quarter of 2020 as compared to the third quarter of 2019 primarily due to lower employee costs.

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Gain (Loss) on Disposition of Assets

There was a $1.6 million gain on disposition of assets in the third quarter of 2020 primarily related to the sale of vehicles, drilling rigs, and other drilling equipment. For the third quarter of 2019, we had a loss of $0.2 million which was primarily related to assets held for sale that were sold which consisted of one drilling rig and miscellaneous drilling rig components.

Other Income (Expense)

Interest expense, net of capitalized interest, decreased $6.8 million between the comparative third quarters of 2020 and 2019 due to an 80% decrease in average long-term debt outstanding and no capitalized interest in the third quarter of 2020 and a lower average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, constructing additional drilling rigs, and constructing gas gathering systems. Because we are not currently undergoing any capital projects, we had no capitalized interest for the third quarter of 2020 compared to $4.2 million for the third quarter of 2019 which was netted against our gross interest of $2.8 million and $13.7 million for the third quarters of 2020 and 2019, respectively. Our average interest rate decreased from 6.3% in the third quarter of 2019 to 3.7% in the third quarter of 2020 and our average debt outstanding decreased $620.3 million in the third quarter of 2020 compared to the third quarter of 2019 primarily due to the Notes being settled with the Plan.

Reorganization Items, Net

Reorganization items, net represent any of the expenses, gains, and losses incurred subsequent to and as a direct result of the Chapter 11 proceedings. For more detail, see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.

Gain (Loss) on Derivatives

Gain (loss) on derivatives decreased by $4.5 million between the comparative third quarters of 2020 and 2019 primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Income Tax Benefit

Income tax benefit was $4.8 million in the third quarter of 2020 compared to $50.8 million in the third quarter of 2019 primarily due to the need of a valuation allowance against our income tax benefit. The income tax benefit was recognized in the Predecessor period ending August 31, 2020. Due to changes in the book basis of our assets in conjunction with our fresh start accounting and our net operating losses, it was determined that a full valuation allowance against our net deferred tax asset was needed as of the Effective Date and the Successor period ending September 30, 2020. Our blended effective tax rate was (4.06%) for the third quarter of 2020 ((3.83%) for the Predecessor period ending August 31, 2020 and 0.00% for the Successor period ending September 30, 2020) compared to 19.63% for the third quarter of 2019. The rate change was primarily due to the need of a valuation allowance against our income tax benefit for the third quarter of 2020. We did not have a current income tax benefit for the third quarter of 2020 or 2019. We paid no income taxes in the third quarter of 2020.

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Year Ended September 30, 2020 versus Year Ended September 30, 2019

Provided below is a comparison of selected operating and financial data after eliminations (in thousands unless otherwise specified):


	Successor			Predecessor			Predecessor
	One Month Ended			Eight Months Ended			Nine Months Ended			Percent Change (1)
	September 30, 2020			August 31, 2020			September 30, 2019
Total revenue	$	32,846		$	276,957		$	510,276		(39)	%
Net loss	$	(6,736)		$	(890,624)		$	(218,088)		NM
Net income attributable to non-controlling interest	$	2,232		$	40,388		$	811		NM
Net loss attributable to Unit Corporation	$	(8,968)		$	(931,012)		$	(218,899)		NM

Oil and Natural Gas:
Revenue	$	13,643		$	103,439		$	241,955		(52)	%
Operating costs excluding depreciation, depletion, and amortization	$	6,674		$	117,691		$	104,320		19	%
Depreciation, depletion, and amortization	$	4,199		$	68,762		$	118,105		(38)	%
Impairment of oil and natural gas properties	$	13,237		$	393,726		$	169,806		140	%
Average oil price (Bbl)	$	28.11		$	31.98		$	57.55		(45)	%
Average NGLs price (Bbl)	$	7.47		$	4.83		$	12.21		(58)	%
Average natural gas price (Mcf)	$	1.72		$	1.14		$	2.07		(42)	%
Oil production (MBbls)	167			1,562			2,341			(26)	%
NGL production (MBbls)	273			2,399			3,657			(27)	%
Natural gas production (MMcf)	2,849			26,563			40,021			(27)	%
Depreciation, depletion, and amortization rate (Boe)	$	4.56		$	7.80		$	8.94		(49)	%

Contract Drilling:
Revenue	$	4,414		$	73,519		$	131,788		(41)	%
Operating costs excluding depreciation	$	2,989		$	51,810		89,505			(39)	%
Depreciation	$	526		$	15,544		$	39,048		(59)	%

Impairment of contract drilling equipment	$	—		$	410,126		$	—		—	%
Impairment of goodwill	$	—		$	—		$	62,809		(100)	%
Percentage of revenue from daywork contracts	100		%	100		%	100		%	—	%
Average number of drilling rigs in use	6.0			11.5			26.8			(59)	%
Average dayrate on daywork contracts	$	17,361		$	18,911		$	18,635		1	%

Mid-Stream:
Revenue	$	14,789		$	99,999		$	136,533		(16)	%
Operating costs excluding depreciation and amortization	$	9,852		$	68,045		$	100,339		(22)	%
Depreciation and amortization	$	2,658		$	29,371		$	35,675		(10)	%
Impairment	$	—		$	63,962		$	2,265		NM
Gas gathered--Mcf/day	345,460			388,506			447,989			(14)	%
Gas processed--Mcf/day	145,263			158,031			165,061			(5)	%
Gas liquids sold--gallons/day	473,371			612,301			644,601			(7)	%

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	Successor			Predecessor			Predecessor
	One Month Ended			Eight Months Ended			Nine Months Ended			Percent Change (1)
	September 30, 2020			August 31, 2020			September 30, 2019

Corporate and Other:
Loss on abandonment of assets	$	—		$	18,733		$	—		—	%
General and administrative expense	$	1,582		$	42,766		$	29,899		48	%
Other depreciation	$	84		$	1,819		$	5,804		(67)	%
Gain (loss) on disposition of assets	$	222		$	89		$	(1,424)		122	%
Other income (expense):
Interest income	$	—		$	58		$	47		23	%
Interest expense, net	$	(826)		$	(22,882)		$	(27,114)		(13)	%
Reorganization costs, net	$	(1,155)		$	133,975		$	—		—	%
Write-off of debt issuance costs	$	—		$	(2,426)		$	—		—	%
Gain (loss) on derivatives	$	3,939		$	(10,704)		$	5,232		NM
Other	$	39		$	2,034		$	(611)		NM
Income tax benefit	$	—		$	(14,630)		$	(53,081)		72	%
Average interest rate	5.9		%	5.5		%	6.4		%	(15)	%
Average long-term debt outstanding	$	146,267		$	526,167		$	732,515		(34)	%

_________________________

1.This is a comparison between the sum of the one month ended Successor period and the eight month ended Predecessor period in 2020 and the nine month ended period in 2019. NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

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Oil and Natural Gas

Oil and natural gas revenues decreased $124.9 million or 52% in the first nine months of 2020 as compared to the first nine months of 2019 primarily due to lower commodity prices and volumes. In the first nine months of 2020, as compared to the first nine months of 2019, oil production decreased 26%, natural gas production decreased 27%, and NGLs production decreased 27%. Including derivatives settled, average oil prices decreased 45% to $31.61 per barrel, average natural gas prices decreased 42% to $1.20 per Mcf, and NGLs prices decreased 58% to $5.10 per barrel.

Oil and natural gas operating costs increased $20.0 million or 19% between the comparative first nine months of 2020 and 2019 primarily due to lower LOE, and gross production taxes partially offset by decreased G&G expenses capitalized.

Depreciation, depletion, and amortization (DD&A) decreased $45.1 million or 38% due primarily to a 49% decrease in the DD&A rate and a 27% decrease in equivalent production.

During the first nine months of 2020, we recorded non-cash ceiling test write-downs of $393.7 million pre-tax ($346.6 million, net of tax). During the first nine months of 2019, we recorded a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax). We recorded expense of $17.6 million related to the write down of our salt water disposal asset that we consider abandoned in first nine months of 2020.

Contract Drilling

Drilling revenues decreased $53.9 million or 41% in the first nine months of 2020 versus the first nine months of 2019. The decrease was due primarily to a 59% decrease in the average number of drilling rigs in use partially offset by an 1% increase in the average dayrate. Average drilling rig utilization decreased from 26.8 drilling rigs in the first nine months of 2019 to 10.9 drilling rigs in the first nine months of 2020.

Drilling operating costs decreased $34.7 million or 39% between the comparative first nine months of 2020 and 2019. The decrease was due primarily to less drilling rigs operating. Contract drilling depreciation decreased $23.0 million or 59% in the first nine months of 2020 versus the first nine months of 2019 also due to less drilling rigs operating and from lower depreciable net book value due to impairments recognized in the first half of 2020.

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

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

Mid-Stream

Our mid-stream revenues decreased $21.7 million or 16% in the first nine months of 2020 as compared to the first nine months of 2019 due primarily to lower gas, NGLs, and condensate prices and volumes partially offset by the recognition of a one-time shortfall fee from one of our producers. Gas processed volumes per day decreased 5% between the comparative periods primarily due to connecting fewer new wells to our processing systems and declining volumes on most of our processing systems partially offset by increased volume from the Cashion system due to the acquisition at the end of 2019. Gas gathered volumes per day decreased 14% between the comparative periods due to fewer new well connects and declining volumes from most of our major systems partially offset by higher volume on our Cashion system.

Operating costs decreased $22.4 million or 22% in the first nine months of 2020 compared to the first nine months of 2019 primarily due to lower purchase prices along with lower purchased volumes. Depreciation and amortization decreased $3.6 million, or 10%, primarily due to impairing the carrying value of several of our systems in the first quarter of 2020.

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

Loss on Abandonment of Assets

During the first quarter of 2020, we evaluated the carrying value of our salt water disposal assets. Based on our revised forecast of asset utilization, we determined certain assets were no longer expected to be used and wrote off certain salt water disposal assets that we now consider abandoned. We recorded expense of $17.6 million related to the write-down of our salt water disposal asset in first quarter of 2020. In the third quarter of 2020, we recorded expense of $1.2 million related to the write-down of our drilling line asset.

General and Administrative

Corporate general and administrative expenses increased $14.4 million or 48% in the first nine months of 2020 as compared to the first nine months of 2019 primarily due to consulting fees paid prior to filing for bankruptcy and costs incurred for separation benefits provided to employees that were part of our reduction in force in April 2020. We incurred $20.2 million in advisory and restructuring fees.

Gain (Loss) on Disposition of Assets

There was a $0.3 million gain on disposition of assets in the first nine months of 2020 primarily related to the sale of vehicles, drilling rigs, and other drilling equipment. For the first nine months of 2019, we had a loss of $1.4 million. Of this amount, we had a gain of $0.5 million was related to assets held for sale that were sold which consisted of four drilling rigs and other drilling components. The remaining loss of $1.9 million was related to the sales of other drilling rig components and vehicles.

Other Income (Expense)

Interest expense, net of capitalized interest, decreased $3.4 million between the comparative first nine months of 2020 and 2019 due primarily to an 34% decrease in average long-term debt outstanding and no capitalized interest in the first nine months of 2020 and by a lower average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, constructing additional drilling rigs, and constructing gas gathering systems. Because we are not currently undergoing any capital projects, we had no capitalized interest for the first nine months of 2020 compared to $12.6 million for the first nine months of 2019 and was netted against our gross interest of $23.7 million and $39.7 million for the first nine months of 2020 and 2019, respectively. Our average interest rate decreased from 6.4% in the first nine months of 2019 to 5.5% in the first nine months of 2020 and our average debt outstanding decreased $247.9 million in the first nine months of 2020 compared to the first nine months of 2019 primarily due to the Notes being settled with the Plan.

Reorganization Items, Net

Write-off of Debt Issuance Costs

Due to the remaining commitments of the Unit credit agreement being terminated by the RBL Lenders', the unamortized debt issuance costs of $2.4 million were written off during the second quarter of 2020.

Gain (Loss) on Derivatives

Gain (loss) on derivatives decreased by $12.0 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

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Income Tax Benefit

Income tax benefit was $14.6 million in the first nine months of 2020 compared to $53.1 million in the first nine months of 2019 primarily due the need of a valuation allowance against what would otherwise be a sizable income tax benefit due to our substantial pre-tax loss for the first nine months of 2020. The income tax benefit was recognized in the Predecessor period ending August 31,2020. Due to changes in the book basis of our assets in conjunction with our fresh start accounting and our net operating losses, it was determined that a full valuation allowance against our net deferred tax asset was needed as of the Effective Date and the Successor period ending September 30, 2020. Our blended effective tax rate was 1.60% for the first nine months of 2020 (1.62% for the Predecessor period ending August 31, 2020 and 0.00% for the Successor period ending September 30, 2020) compared to 19.57% for the first nine months of 2019. The rate change was primarily due to the need of a valuation allowance against our income tax benefit for the first nine months of 2020. We recognized $0.9 million of current income tax benefit for the first nine months of 2020 due to the acceleration of our alternative minimum tax credit refund as prescribed by the CARES act. We did not have a current income tax benefit for the first nine months of 2019. We paid no income taxes in the first nine months of 2020.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

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

Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas production. These prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our NGLs and natural gas production. Historically, these prices have fluctuated and we expect this to continue. The prices for oil, NGLs, and natural gas also affect the demand for our drilling rigs and the amount we can charge for the use of our drilling rigs. Based on our first nine months 2020 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 $279,000 per month ($3.4 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 $160,000 per month ($1.9 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 $264,000 per month ($3.2 million annualized) change in our pre-tax operating cash flow.

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

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At September 30, 2020, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Oct'20 - Dec'20

Natural gas - basis swap

30,000 MMBtu/day

$(0.275)

NGPL TEXOK

Oct'20 - Dec'20

Natural gas - basis swap

20,000 MMBtu/day

$(0.455)

PEPL

Jan'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$(0.215)

NGPL TEXOK

Oct'20 - Dec'20

Natural gas - swap

30,000 MMBtu/day

$2.753

IF - NYMEX (HH)

Jan'21 - Oct'21

Natural gas - swap

50,000 MMBtu/day

$2.818

IF - NYMEX (HH)

Nov'21 - Dec'21

Natural gas - swap

75,000 MMBtu/day

$2.880

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - swap

5,000 MMBtu/day

$2.605

IF - NYMEX (HH)

Jan'23 - Dec'23

Natural gas - swap

22,000 MMBtu/day

$2.456

IF - NYMEX (HH)

Oct'20 - Dec'20

Natural gas - collar

30,000 MMBtu/day

$2.50 - $2.80

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - collar

35,000 MMBtu/day

$2.50 - $2.68

IF - NYMEX (HH)

Oct'20 - Dec'20

Crude oil - swap

4,000 Bbl/day

$43.35

WTI - NYMEX

Jan'21 - Dec'21

Crude oil - swap

3,000 Bbl/day

$44.65

WTI - NYMEX

Jan'22 - Dec'22

Crude oil - swap

2,300 Bbl/day

$42.25

WTI - NYMEX

Jan'23 - Dec'23

Crude oil - swap

1,300 Bbl/day

$43.60

WTI - NYMEX

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our Exit Credit Agreement and Superior credit agreement. Borrowings under our Exit Credit Agreement and Superior credit agreement carry variable interest rates. A 1% increase in the interest rates on the outstanding borrowings under these facilities at September 3, 2020 would reduce our annual pre-tax cash flow by approximately $1.6 million. For further information, see Note 9 – Long-Term Debt and Other Long-Term Liabilities.

Item 4. Controls and Procedures

Our management, which includes 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 (Exchange Act)) (Disclosure Controls) 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 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 Internal Control over Financial Reporting (ICFR) and make modifications as necessary; our intent in this regard is that the Disclosure Controls and ICFR will be modified as systems change, and conditions warrant.

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures under Exchange Act Rule 13a-15. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were not effective as of September 30, 2020 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

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management review controls over complex accounting matters was present. Key elements of effectively designed management review controls include the establishment of documentation standards for process owners to document the substance of their work related to critical accounting estimates, complex accounting matters, and non-routine transactions. Effectively designed management review controls must also have an established process that allows senior accounting personnel having the appropriate knowledge of the subject matter to have enough time to perform effective reviews. Necessary elements for effectively designed management review controls were either not present at June 30, 2020 or not present for a sufficient period of time in order to conclude our disclosure controls and procedures were effective at June 30, 2020. This continued to be the case at September 30, 2020.

Plan for Remediation of the Material Weakness. We are addressing 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, providing additional training for employees responsible for performing important management review controls, and supplementing internal resources with external expertise when appropriate.

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

Changes in Internal Controls. There were no other changes in our ICFR during the quarter ended September 30, 2020, that materially affected our ICFR or are reasonably likely to materially affect it, as defined in Rule 13a – 15(f) under the Exchange Act.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Voluntary Petitions under Chapter 11 of the Bankruptcy Code

On May 22, 2020, the Debtors filed the Bankruptcy Petitions seeking relief under the Bankruptcy Code. The commencement of the Chapter 11 Cases automatically stayed all of the proceedings and actions against the Debtors (other than certain regulatory enforcement matters). On the Effective Date, the automatic stay was terminated and replaced with the injunction provisions in the Confirmation Order of the Plan. For further information, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11—Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code.

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, 2019, 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.

Other than as set forth below, 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, 2019, Part II, Item 1A in our Form 10-Q for the quarter ended March 31, 2020 and Part II, Item 1A in our Form 10-Q for the quarter ended June 30, 2020.

Even though the Plan has been consummated, we may not be able to achieve our stated goals and continue as a going concern.

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

Furthermore, even though our debt was reduced through a plan of reorganization, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the Chapter 11 Cases. Our access to additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms.

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

Our ability to fund our operations and our capital expenditures requires a significant amount of cash. Our current principal sources of liquidity include the available borrowing capacity under the Exit Credit Agreement and cash flow generated from operations. If our cash flow from operations decreases, we may not have the ability to expend the capital necessary to maintain our current operations, negatively impacting our future revenues.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of the Exit Credit Agreement, (ii) our ability to maintain adequate cash on hand, and (iii) our ability to generate cash flow from operations.

Restrictive covenants in our credit facilities may limit our financial and operating flexibility.

As of September 30, 2020, we had approximately $132.0 million of outstanding indebtedness under our Exit Credit Agreement and $12.0 million of outstanding indebtedness under our Superior credit agreement. Our financing agreements permit us to incur additional indebtedness and other obligations. In addition, we may seek amendments or waivers from our existing lenders to the extent we need to incur indebtedness above amounts currently permitted by our financing agreements.

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

•incur additional indebtedness;

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•incur additional liens;

•pay dividends or make other distributions;

•make investments, loans or advances;

•sell or discount receivables;

•enter into mergers;

•sell properties;

•terminate swap agreements;

•enter into transactions with affiliates;

•maintain gas imbalances;

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

•enter into swap agreements;

•enter into sale and leaseback agreements;

•amend our organizational documents; and

•make capital expenditures.

The credit facilities also require us to comply with certain financial maintenance covenants as discussed above including a Net Leverage Ratio, Current Ratio and Interest Coverage Ratio. See Note 9 – Long-Term Debt and Other Long-Term Liabilities for additional information.

A breach of any of these restrictive covenants could result in a default under the credit facilities. If a default occurs, the lenders may elect to declare all borrowings thereunder outstanding, together with accrued interest and other fees, to be immediately due and payable. If we are unable to repay our indebtedness when due or declared due, the lenders thereunder will also have the right to proceed against the collateral pledged to them to secure the indebtedness.

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

In connection with our emergence from bankruptcy on the Effective Date, we determined that the company qualified for fresh start accounting in accordance with ASC Topic 852, Reorganizations, pursuant to which our reorganization value, which represents the fair value of the entity before considering liabilities, will be allocated to the fair value of assets in conformity with the purchase method of accounting for business combinations. We will state our liabilities, other than deferred taxes, at a present value of amounts expected to be paid. Thus, our balance sheets and results of operations will not be comparable in many respects to balance sheets and consolidated statements of operations data for periods prior to our adoption of fresh start accounting. You will not be able to compare information reflecting our post-emergence financial statements to information for periods prior to our emergence from bankruptcy, without making adjustments for fresh start accounting. The lack of comparable historical information may discourage investors from purchasing our New Common Stock.

Our New Common Stock does not have a market maker for trading on the OTC Markets, and thus may have a limited market and lack of liquidity.

Some investors have begun to quote our New Common Stock on the OTC Pink Marketplace. [However, investors should be aware that no firm is currently making a market in the New Common Stock and holders of the New Common Stock may have a difficult time selling their shares. A potential market maker has filed with FINRA an initial Form 211, in accordance with Rule 15c2-11 under the Exchange Act, for quotation of the New Common Stock on the OTC Markets. There is no assurance that the Form 211 will be cleared by FINRA or when that will occur.]

Even if the Form 211 is cleared by FINRA and we do have a market maker for our New Common Stock, being quoted on the OTC Pink Marketplace may have an unfavorable impact on our stock price and liquidity. The OTC Pink Marketplace is a significantly more limited market than the NYSE or The Nasdaq Stock Market. The quotation of our shares on such marketplace may result in a less liquid market available for existing and potential stockholders to trade shares of our New Common Stock, could depress the trading price of our New Common Stock, and could have a long-term adverse impact on our

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ability to raise capital in the future. There can be no assurance that there will be an active market for our shares of New Common Stock, either now or in the future, or that stockholders will be able to liquidate their investment or liquidate it at a price that reflects the value of the business.

On the effective date of the Plan, the composition of our board of directors changed substantially.

Pursuant to our Plan, the composition of our board of directors changed significantly. All the six members of our current board of directors were appointed to the board in connection with our emergence from bankruptcy. David T. Merrill, who was the seventh director appointed to our board under the Plan, left the company on October 22, 2020. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine our future. There is no guarantee that the new board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and our plans may differ materially from those of the past.

Public health events that are outside of our control, including pandemics, epidemics and infectious disease outbreaks, such as the recent global outbreak of COVID-19, have materially and adversely affected, and may further materially and adversely affect, our business.

We face risks related to epidemics, pandemics, outbreaks, or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect their financial condition. For example, the outbreak of the COVID-19 virus has spread across the globe and impacted financial markets and worldwide economic activity and may continue to adversely affect our operations or the health of our workforce by rendering employees or contractors unable to work or unable to access the our facilities for an indefinite period of time. As of the time of this filing, cases of COVID-19 in the U.S. were increasing rapidly, particularly in Texas, where we conduct significant operations. In addition, the effects of COVID-19 and concerns regarding its global spread have negatively impacted the domestic and international demand for crude oil and natural gas, which has adversely affected crude oil prices and resulted in significant price volatility. As the duration and full impact from COVID-19 is difficult to predict, the extent to which it may negatively affect the our operating results or the duration of any potential business disruption is uncertain. Any potential impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control. These potential impacts, while uncertain, could adversely affect the our operating results.

We have identified a material weakness in our internal control over financial reporting, or ICFR. If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which could harm our business and the trading price of our stock.

As previously disclosed in our Quarterly Report on Form 10-Q for the period ended June 30, 2020, during the preparation of 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. Such material weakness continues to exist. A material weakness is a deficiency, or combination of deficiencies, in ICFR such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The existence of a material weakness could result in errors in our financial statements, cause us to fail to meet our reporting obligations and cause investors to lose confidence in our reported financial information, leading to a decline in the trading price of our stock.

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

The following table provides information relating to our repurchase of common stock for the two months ended August 31, 2020:

Period

(a)
Total Number of Shares Purchased

(b)
Average Price Paid
Per Share

(d)
Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs

July 1, 2020 to July 31, 2020

—

August 1, 2020 to August 31, 2020

—

Total

—

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

Exhibits:


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

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

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

101.INS			XBRL Instance Document.

101.SCH			XBRL Taxonomy Extension Schema Document.

101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF			XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB			XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document.

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SIGNATURES

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


		Unit Corporation

Date:	January 28, 2021	By: /s/ Philip B. Smith
		PHILIP B. SMITH
		President and Chief Executive Officer

Date:	January 28, 2021	By: /s/ Thomas D. Sell
		THOMAS D. SELL
		Interim Chief Financial Officer