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

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 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 ☒

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 ☒

The registrant had 54,504,879 shares of common stock outstanding prior to the registrant's emergence from bankruptcy on September 3, 2020.

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TABLE OF CONTENTS


		Page Number
	PART I. Financial Information

Item 1.	Financial Statements (Unaudited)

	Unaudited Condensed Consolidated Balance Sheets June 30, 2020 and December 31, 2019	4

	Unaudited Condensed Consolidated Statements of Operations Three and Six Months Ended June 30, 2020 and 2019	6

	Unaudited Condensed Consolidated Statements of Comprehensive Loss Three and Six Months Ended June 30, 2020 and 2019	7

	Unaudited Condensed Consolidated Statements of Changes in Shareholders' Equity Three and Six Months Ended June 30, 2020 and 2019	8

	Unaudited Condensed Consolidated Statements of Cash Flows Six months ended June 30, 2020 and 2019	10

	Notes to Unaudited Condensed Consolidated Financial Statements	12

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	76

Item 4.	Controls and Procedures	77

	PART II. Other Information

Item 1.	Legal Proceedings	78

Item 1A.	Risk Factors	78

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	82

Item 3.	Defaults On Senior Securities	82

Item 4.	Mine Safety Disclosures	82

Item 5.	Other Information	82

Item 6.	Exhibits	83

Signatures		85

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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 SEC will automatically update and supersede information in this report.

These forward-looking statements 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 for the year;

•our anticipated capital budgets;

•our financial condition and liquidity;

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

•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;

•future compliance with covenants under our debt agreements;

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•inability to maintain relationship with suppliers, customers, employees and other third parties following emergence from bankruptcy;

•ability to satisfy our short- or long-term liquidity needs following emergence from bankruptcy, including ability to generate sufficient cash flow from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs and ability to continue as a going concern;

•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 (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	June 30, 2020		December 31, 2019
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	36,994	$	571
Accounts receivable, net of allowance for doubtful accounts of $3,961 and $2,332 at June 30, 2020 and December 31, 2019, respectively	54,146		82,656
Materials and supplies	110		449
Current derivative asset (Note 12)	—		633

Current income tax receivable	850		1,756
Assets held for sale (Note 5)	—		5,908
Prepaid expenses and other	16,659		13,078
Total current assets	108,759		105,051
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties	6,566,669		6,341,582
Unproved properties not being amortized	30,342		252,874
Drilling equipment	1,296,319		1,295,713
Gas gathering and processing equipment	833,402		824,699
Saltwater disposal systems	43,843		69,692
Land and building	59,080		59,080
Transportation equipment	16,780		29,723
Other	58,036		57,992
	8,904,471		8,931,355
Less accumulated depreciation, depletion, amortization, and impairment	7,903,051		6,978,669
Net property and equipment	1,001,420		1,952,686


Right of use asset (Note 14)	7,828		5,673
Other assets	22,371		26,642
Total assets ⁽¹⁾	$	1,140,378	$	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 (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED


	June 30, 2020		December 31, 2019
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	26,808	$	84,481
Accrued liabilities (Note 7)	31,384		46,562
Current operating lease liability (Note 14)	4,666		3,430
Current portion of long-term debt (Note 8)	124,000		108,200
Debtor-in-possession financing (Note 8)	8,000		—
Current derivative liabilities (Note 12)	5,011		—
Current portion of other long-term liabilities (Note 8)	13,628		17,376
Total current liabilities	213,497		260,049
Long-term debt less debt issuance costs (Note 8)	34,000		663,216
Non-current derivative liabilities (Note 12)	145		27
Operating lease liability (Note 14)	3,012		2,071
Other long-term liabilities (Note 8)	84,722		95,341
Liabilities subject to compromise (Note 2)	759,720		—
Deferred income taxes	4,750		13,713
Commitments and contingencies (Note 15)
Shareholders’ equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued	—		—
Common stock, $0.20 par value, 175,000,000 shares authorized, 54,617,677 and 55,443,393 shares issued as of June 30, 2020 and December 31, 2019, respectively	10,704		10,591
Capital in excess of par value	648,128		644,152

Retained earnings (deficit)	(787,008)		199,135
Total shareholders’ equity attributable to Unit Corporation	(128,176)		853,878
Non-controlling interests in consolidated subsidiaries	168,708		201,757
Total shareholders' equity	40,532		1,055,635
Total liabilities⁽¹⁾ and shareholders’ equity	$	1,140,378	$	2,090,052

_______________________

(1)Unit Corporation's consolidated total assets as of June 30, 2020 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $49.8 million and $354.0 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of June 30, 2020 include total current and long-term liabilities of the VIE of $25.2 million and $39.7 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 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 16 – Variable Interest Entity Arrangements.

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
	(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	26,956	$	77,815	$	75,478	$	163,910
Contract drilling	29,202		43,037		65,834		94,192
Gas gathering and processing	32,849		44,294		70,071		96,735
Total revenues	89,007		165,146		211,383		354,837
Expenses:
Operating costs:
Oil and natural gas	71,540		36,242		102,203		68,956
Contract drilling	20,951		29,308		46,400		60,709
Gas gathering and processing	22,612		32,491		50,223		71,846
Total operating costs	115,103		98,041		198,826		201,511
Depreciation, depletion, and amortization	35,960		66,292		97,577		128,418
Impairments (Note 3)	109,318		—		851,242		—
Loss on abandonment of assets (Note 3)	—		—		17,554		—
General and administrative	25,814		10,064		37,367		19,805
(Gain) loss on disposition of assets	877		(422)		1,267		1,193
Total operating expenses	287,072		173,975		1,203,833		350,927
Income (loss) from operations	(198,065)		(8,829)		(992,450)		3,910
Other income (expense):
Interest, net (excludes interest expense of $5.4 million on senior subordinated notes subject to compromise, for the three and six months ended June 30, 2020)	(7,608)		(8,995)		(20,865)		(17,533)
Write-off of debt issuance costs (Note 8)	(2,426)		—		(2,426)		—
Gain (loss) on derivatives (Note 12)	(6,937)		7,927		(6,454)		995
Reorganization items, net (Note 2)	(7,027)		—		(7,027)		—
Other, net	43		6		103		11
Total other income (expense)	(23,955)		(1,062)		(36,669)		(16,527)
Loss before income taxes	(222,020)		(9,891)		(1,029,119)		(12,617)
Income tax benefit:
Current	—		—		(917)		—
Deferred	(6,455)		(1,874)		(8,963)		(2,318)
Total income tax benefit	(6,455)		(1,874)		(9,880)		(2,318)
Net loss	(215,565)		(8,017)		(1,019,239)		(10,299)
Net income (loss) attributable to non-controlling interest	84		492		(33,096)		1,714
Net loss attributable to Unit Corporation	$	(215,649)	$	(8,509)	$	(986,143)	$	(12,013)
Net loss attributable to Unit Corporation per common share (Note 6):
Basic	$	(4.03)	$	(0.16)	$	(18.50)	$	(0.23)
Diluted	$	(4.03)	$	(0.16)	$	(18.50)	$	(0.23)

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
	(In thousands)
Net loss	$	(215,565)	$	(8,017)	$	(1,019,239)	$	(10,299)
Other comprehensive income (loss), net of taxes:
Unrealized loss on securities, net of tax of $0, ($9), $0, and ($2)	—		(30)		—		(6)

Comprehensive loss	(215,565)		(8,047)		(1,019,239)		(10,305)
Less: Comprehensive income (loss) attributable to non-controlling interest	84		492		(33,096)		1,714
Comprehensive loss attributable to Unit Corporation	$	(215,649)	$	(8,539)	$	(986,143)	$	(12,019)

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

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


	Three Months Ended June 30, 2020
	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Capital in Excess of Par Value		Accumulated Other Comprehensive Income		Retained Deficit		Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, March 31, 2020	$	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	$	10,704	$	648,128	$	—	$	(787,008)	$	168,708	$	40,532


	Six Months Ended June 30, 2020
	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Capital in Excess of Par Value		Accumulated Other Comprehensive Income		Retained Earnings (Deficit)		Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, December 31, 2019	$	10,591	$	644,152	$	—	$	199,135	$	201,757	$	1,055,635
Net loss	—		—		—		(986,143)		(33,096)		(1,019,239)

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

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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	Three Months Ended June 30, 2019
	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Capital in Excess of Par Value		Accumulated Other Comprehensive Loss		Retained Earnings		Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, March 31, 2019	$	10,578	$	633,361	$	(457)	$	749,510	$	202,867	$	1,595,859
Net income (loss)	—		—		—		(8,509)		492		(8,017)
Other comprehensive loss (net of tax of ($9))	—		—		(30)		—		—		(30)
Total comprehensive loss											(8,047)
Activity in employee compensation plans	12		5,408		—		—		—		5,420
Balances, June 30, 2019	$	10,590	$	638,769	$	(487)	$	741,001	$	203,359	$	1,593,232


	Six Months Ended June 30, 2019
	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Capital in Excess of Par Value		Accumulated Other Comprehensive Income (Loss)		Retained Earnings		Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, December 31, 2018	$	10,414	$	628,108	$	(481)	$	752,840	$	202,563	$	1,593,444
Cumulative effect adjustment for adoption of ASUs	—		—		—		174		—		174
Net income (loss)	—		—		—		(12,013)		1,714		(10,299)
Other comprehensive loss (net of tax of ($2))	—		—		(6)		—		—		(6)
Total comprehensive loss											(10,305)
Distributions to non-controlling interest	—		—		—		—		(918)		(918)
Activity in employee compensation plans	176		10,661		—		—		—		10,837
Balances, June 30, 2019	$	10,590	$	638,769	$	(487)	$	741,001	$	203,359	$	1,593,232

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Six Months Ended
	June 30,
	2020		2019
	(In thousands)
OPERATING ACTIVITIES:
Net loss	$	(1,019,239)	$	(10,299)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	97,577		128,418
Impairments (Note 3)	851,242		—
Loss on abandonment of assets (Note 3)	17,554		—
Amortization of debt issuance costs and debt discount (Note 8)	1,079		1,115
(Gain) loss on derivatives (Note 12)	6,454		(995)
Cash receipts (payments) on derivatives settled (Note 12)	(691)		5,314
Loss on disposition of assets	1,267		1,193
Write-off of debt issuance costs	2,426		—
Deferred tax benefit	(8,963)		(2,318)
Employee stock compensation plans	4,179		11,187
Bad debt expense	1,923		—
ARO liability accretion (Note 9)	1,169		1,168
Contract assets and liabilities, net (Note 4)	1,790		(1,283)
Noncash reorganization items	7,027		—
Other, net	11,493		(51)

Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	26,587		26,939
Material and supplies	43		(43)
Prepaid expenses and other	(2,703)		(377)
Accounts payable	(22,876)		(30,374)
Accrued liabilities	48,244		(1,245)
Income taxes	906		—
Contract advances	(21)		(848)

Net cash provided by operating activities	26,467		127,501
INVESTING ACTIVITIES:
Capital expenditures	(23,804)		(246,638)
Producing properties and other acquisitions	(210)		(3,313)
Proceeds from disposition of property and equipment	4,497		7,340


Net cash used in investing activities	(19,517)		(242,611)
FINANCING ACTIVITIES:
Borrowings under line of credit, including borrowings under DIP credit facility	79,400		271,200
Payments under line of credit	(38,100)		(160,200)

DIP financing costs	(990)		—
Net payments on finance leases	(2,061)		(1,980)
Employee taxes paid by withholding shares	(43)		(4,073)




Distributions to non-controlling interests	—		(918)

Bank overdrafts	(8,733)		5,298
Net cash provided by financing activities	29,473		109,327
Net increase (decrease) in cash and cash equivalents	36,423		(5,783)
Cash and cash equivalents, beginning of year	571		6,452
Cash and cash equivalents, end of year	$	36,994	$	669

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - CONTINUED


	Six Months Ended
	June 30,
	2020		2019
	(In thousands)
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)	$	4,795	$	15,748
Income taxes	—		—

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	5,974		(6,260)
Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations	3,548		(2,057)
Non-cash trade of property, plant, and equipment	548		—

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

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, through 50% ownership, to direct those activities that most significantly affect the economic performance of Superior as further described in Note 16 – Variable Interest Entity Arrangements.

The condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This report should be read in conjunction 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 March 16, 2020.

The following unaudited condensed consolidated financial statements have been prepared in accordance with FASB ASC Topic 852, Reorganizations. This guidance requires that transactions and events directly associated with a Chapter 11 reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting for and presentation of liabilities. See Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern.

In the opinion of our management, the unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state:

•Balance Sheets as of June 30, 2020 and December 31, 2019;

•Statements of Operations for the three and six months ended June 30, 2020 and 2019;

•Statements of Comprehensive Loss for the three and six months ended June 30, 2020 and 2019;

•Statements of Changes in Shareholders' Equity for the three and six months ended June 30, 2020 and 2019; and

•Statements of Cash Flows for the six months ended June 30, 2020 and 2019.

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. Results for the six months ended June 30, 2020 and 2019 are not necessarily indicative of the results we may realize for the full year of 2020, or that we realized for the full year of 2019.

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 loss or shareholders' equity.

NOTE 2 – CHAPTER 11 PROCEEDINGS, LIQUIDITY, AND ABILITY TO CONTINUE AS A GOING CONCERN

Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On May 22, 2020 (Petition Date), Unit and 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 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.

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On May 22, 2020, the Debtors entered into a Restructuring Support Agreement (RSA) with (i) holders of 100% of the aggregate principal amount of loans outstanding under the Senior Credit Agreement, dated as of September 13, 2011 (as amended, the Unit credit agreement, together with the loan facility, the Unit credit facility), by and among the company, UPC and UDC, as borrowers, the institutions named as lenders (RBL Lenders) and BOKF, NA dba Bank of Oklahoma, as administrative agent (RBL Agent) and (ii) holders of over 70% of the aggregate outstanding principal amount of the company’s 6.625% senior subordinated notes due 2021 (Notes). In accordance with the RSA, 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 and approving the disclosure statement on a final basis.

As contemplated by the RSA, the 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 a $36.0 million new money multi-draw loan facility (DIP credit facility).

Under the Bankruptcy Code, subject to certain exceptions, filing the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising before the Petition Date. Accordingly, although filing the Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors were stayed from taking any actions against the Debtors because of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. As described below, substantially all of the Debtors’ pre-petition liabilities were subject to settlement under the Bankruptcy Code (except for payments to UDC’s vendors and suppliers, which were not affected by the Chapter 11 Cases). Superior and its subsidiaries were not parties to the RSA and were not Debtors in the Chapter 11 Cases.

Under the Bankruptcy Code, subject to certain exceptions, the Debtors assumed, assigned or rejected certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieved the Debtors of performing their future obligations under such executory contract or unexpired lease but entitled the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases were able to assert unsecured claims in the Bankruptcy Court against the applicable Debtors’ estate for such damages. Generally, the assumption of an executory contract or unexpired lease required the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and adequately assure future performance. Any description of an executory contract or unexpired lease with the Debtors in this report, including where applicable a quantification of a Debtor’s obligations under any such executory contract or unexpired lease with the Debtor is qualified by any rejection rights the Debtor had under the Bankruptcy Code. Further, nothing herein is or will be deemed an admission regarding any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto. On July 22, 2020, the Debtors filed the Supplement to the Debtors' First Revised Proposed Joint Chapter 11 Plan [Docket No. 249], which included as Exhibit G the Schedule of Assumed Executory Contracts and Unexpired Leases, listing executory contracts and unexpired leases to be assumed under the Plan, and included as Exhibit H the Schedule of Rejected Executory Contracts and Unexpired Leases, which listed all executory contracts and unexpired leases to be rejected under the Plan. On July 31, 2020 and September 2, 2020, the Debtors filed the Notice of Filing Second Supplement to the Debtors’ First Revised Proposed Joint Chapter 11 Plan [Docket No. 307] and the Notice of Filing Fourth Plan Supplement [Docket No. 385], respectively, which included modifications to the Schedule of Assumed Executory Contracts and Unexpired Leases and the Schedule of Rejected Executory Contracts and Unexpired Leases.

On September 3, 2020 (Effective Date), the Debtors emerged from the Chapter 11 Cases and the various claims and interests in the Debtors received the following treatment:

•Each lender under the Unit credit facility and the DIP credit facility described below received its pro rata share of revolving longs, term loans and letter of credit participations under the Exit Facility described below, in exchange for that lender’s allowed claims under the Unit credit facility or DIP credit facility and each lender under the DIP facility was issued (or will be issued promptly following the Effective Date) its pro rata share of an equity fee under the Equity Facility equal to 5% of the new common shares of reorganized Unit (New Common Stock) (subject to dilution by shares reserved for issuance under a management incentive plan and upon exercise of the warrants described below);

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•Each holder of the Notes will receive 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 will receive its pro rata share of New Common Stock based on equity allocations at each of Unit and UPC, respectively;

•Each retained or former employee with a claim for vested severance benefits may opt in to a settlement to receive a cash payment for the claim in lieu of an allocation of New Common Stock otherwise provided to holders of general unsecured claims;

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

•Each holder of the company’s common stock outstanding prior to the Effective Date (Old Common Stock) that did not opt out of the release under the Plan will 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. (References in this report to our “common stock” refer to our Old Common Stock outstanding prior to the Effective Date.)

Under the Plan, the company will issue shares of New Common Stock to holders of the Notes and to holders of certain allowed general unsecured claims against the Debtors, and will issue the Warrants to holders of Unit’s Old Common Stock that did not opt out of the releases under the Plan. The company is currently seeking to facilitate trading of the New Common Stock on one of the OTC markets. The company expects to complete this process and issue the New Common Stock and the Warrants during the fourth quarter of 2020.

On the Effective Date, the company entered into a Warrant Agreement (Warrant Agreement) with American Stock Transfer & Trust Company, LLC. Under the Plan, the Warrants will be issued to holders of shares of Unit’s Old Common Stock outstanding prior to the Effective Date (including holders of certain equity awards), exercisable for up to an aggregate of approximately 1.8 million shares of New Common Stock. The exercise price of the Warrants will be determined and the Warrants will become exercisable once all general unsecured claims asserted against the Debtors are resolved. The company will calculate the initial exercise price per share for the Warrants, which will be set at an amount that implies a recovery by holders of the Notes of the $650 million principal amount of the Notes plus interest thereon to the May 15, 2021 maturity date of the Notes. 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) and (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.

Events of Default

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. Additionally, other events of default, including cross-defaults, existed or occurred under these debt agreements. As a result, the amount owed under the Unit credit facility has been classified as current as of June 30, 2020. The amount owed in respect of the Notes has been classified as liabilities subject to compromise. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Debtors. Superior and its subsidiaries were not parties to the Chapter 11 Cases, and the Chapter 11 Cases did not result in an event of default under the Superior credit agreement (as defined below). In addition, the Debtors’ filing of the Bankruptcy Petitions constituted a termination event regarding their hedge agreements, which allowed the counterparties to those hedge agreements to terminate the outstanding hedges, and those termination events were not stayed under 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), notwithstanding certain provisions triggered by the filing of the Chapter 11 Cases.

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

We had incurred significant losses and were in a negative working capital position as of June 30, 2020. Our cash balance as of June 30, 2020 was $37.0 million (including $23.8 million relating to Superior) and we had $124.0 million outstanding on our Unit credit agreement as of June 30, 2020. The Unit credit agreement had a scheduled maturity date of October 18, 2023

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that, absent the filing of the Chapter 11 Cases, 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). In addition, filing the Chapter 11 Cases resulted in events of default under the Unit credit agreement and accelerated the Debtors' obligations under the Unit credit agreement. Because of these circumstances, our debt associated with the Unit credit agreement is reflected as a current liability in our consolidated balance sheet as of June 30, 2020 and December 31, 2019. In addition, on May 22, 2020, the RBL Lenders' remaining commitments under the Unit credit facility were terminated.

To provide liquidity to fund our operations and the Chapter 11 Cases, the Debtors entered into the DIP credit agreement. Prior to 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 agreement and subject to the Bankruptcy Court’s orders. As of June 30, 2020, we had borrowed $8.0 million under the DIP credit facility.

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 such holder was issued on the Effective Date (or will be issued 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).

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), providing for a $140.0 million senior secured revolving credit facility (new 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 and its subsidiaries)(the Guarantors), (iii) the lenders party thereto from time to time and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent.

Borrowings under the exit credit agreement mature on March 1, 2024. Revolving Loans and Term Loans (each as defined in the exit credit agreement) under 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 it 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 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. The initial borrowing base under the exit credit agreement is $140.0 million.

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On the Effective Date, the Borrowers had (i) $40.0 million in principal amount of Term Loans outstanding under the new term loan facility, (ii) $92.0 million in principal amount of Revolving Loans outstanding under the new RBL facility and (iii) approximately $6.7 million of outstanding letters of credit.

Going Concern

In addition to reorganizing our capital structure in the Chapter 11 Cases, we have taken several actions to alleviate the conditions that cause substantial doubt about our ability to continue as a going concern, including (i) minimizing capital expenditures, (ii) aggressively managing working capital, (iii) further reducing recurring operating expenses, and (iv) exploring potential business transactions. However, the significant risks and uncertainties related to our liquidity and Chapter 11 Cases at June 30, 2020 raised substantial doubt about our ability to continue as a going concern. We therefore concluded as of such date there continued to be substantial doubt about our ability to continue as a going concern.

We prepared our condensed consolidated financial statements on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements include no adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Fresh Start Accounting

Our consolidated financial statements will be required to be prepared with the application of fresh start accounting following the Effective Date. Under the principles of fresh start accounting, a new reporting entity is considered to be created and we will allocate the aggregate value of the reorganized company to its individual assets and liabilities based on their estimated fair values as of the Effective Date. The enterprise value of the new reporting entity was estimated to be approximately $270.0 million to $380.0 million, with a midpoint of $325.0 million, based on an assumed effective date of the Plan of August 31, 2020. As a result of the anticipated application of fresh start accounting and the effects of the reorganization of our capital structure under the Plan, the consolidated financial statements on or after the Effective Date will not be comparable with the consolidated financial statements before that date. Among other items, lack of comparability before the Effective Date in our financial statements may exist with regard to our deferred tax positions. The Internal Revenue Service Code (IRC) of 1986, as amended, provides that a debtor in a Chapter 11 bankruptcy case may exclude cancellation of debt income (CODI) from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. Following the Effective Date, the CODI may reduce some or all of the amount of prior U.S. tax attributes, which can include net operating losses, capital losses, and tax basis in assets. The amount of the remaining U.S. deferred tax assets, against which a full valuation exists, will be limited under IRC Section 382 due to the change in control resulting from the Plan.

Financial Statement Classification of Liabilities Subject to Compromise

Liabilities subject to compromise represent liabilities incurred before the commencement of the bankruptcy proceedings which may be affected by the Chapter 11 Cases. These amounts represent allowed claims and our best estimate of claims expected to be allowed which will be resolved as part of the bankruptcy proceedings. These claims remain subject to future adjustments. Adjustments may result from negotiations, actions of the Bankruptcy Court, determination as to the value of any collateral securing claims, or other various events. A difference between liability amounts estimated by us and claims filed by creditors will be investigated and the Bankruptcy Court will make a final determination of the amount of allowable claims. Our

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credit facility is fully secured and is not considered a liability subject to compromise. Liabilities subject to compromise include the following:


	June 30, 2020
	(In thousands)
6.625% senior subordinated notes due 2021 (including accrued interest as of the Petition Date)	671,724
Accounts payable	735
Employee separation benefit plan obligations	22,624
Litigation settlements	45,000
Royalty suspense accounts payable	19,637
Total liabilities subject to compromise	$	759,720

During the three months ended June 30, 2020, we had a reduction in force and incurred additional expenses of $15.4 million for benefits to be paid under our Separation Benefit Plan. These expenses were recorded as operating costs in our consolidated statements of operations. Because these amounts are unsecured, the total amount owed to separated employees is subject to compromise.

Interest Expense

The Debtors have 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 three and six months ended June 30, 2020 was approximately $5.4 million, representing interest expense from the Petition Date through June 30, 2020. In addition, the Debtors did not make the required interest payment on the Notes of $21.5 million on May 15, 2020.

Reorganization Items

Reorganization items represent the direct and incremental costs of the Chapter 11 Cases, like professional fees, pre-petition liability claim adjustments, and losses related to terminated contracts that are probable and can be estimated. Reorganization items consisted of the following for the three and six months ended June 30, 2020:


	Amount
	(In thousands)
Professional fees incurred	$	4,822
Adjustment to unamortized debt issuance costs associated with the 6.625% senior subordinated notes due 2021	2,205
Total reorganization items	$	7,027

Financial Statements of the Debtors

The financial statements below represent condensed combined financial statements of the Debtors, which excludes non-debtor entities. Intercompany transactions among the Debtors have been eliminated in the financial statements contained below. Intercompany transactions among the Debtors and the non-debtor subsidiaries have not been eliminated in the Debtors' financial statements below.

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UNIT CORPORATION (DEBTOR-IN-POSSESSION)

Condensed Combined Balance Sheets (Unaudited)


	June 30, 2020
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	13,214
Accounts receivable	33,628
Intercompany accounts receivable	5,290
Materials and supplies	110
Current income tax receivable	850
Prepaid expenses and other	9,338
Total current assets	62,430
Intercompany investment	338,809
Net property and equipment	658,041
Right of use asset	3,337
Other assets	16,626
Total assets	$	1,079,243
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	16,828
Intercompany accounts payable	4,364
Accrued liabilities	25,355
Current operating lease liability	2,154
Current portion of long-term debt	124,000
Debtor-in-possession financing	8,000
Current derivative liability	5,011
Current portion of other long-term liabilities	5,615
Total current liabilities	191,327
Non-current derivative liabilities	145
Operating lease liability	1,146
Other long-term liabilities	81,623
Liabilities subject to compromise	759,720
Deferred income taxes	4,750
Shareholders’ equity:
Total shareholders’ equity attributable to Unit Corporation	(128,176)
Non-controlling interests in consolidated subsidiaries	168,708
Total shareholders' equity	40,532
Total liabilities and shareholders’ equity	$	1,079,243

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UNIT CORPORATION (DEBTOR-IN-POSSESSION)

Condensed Combined Statements of Operations (Unaudited)


	Three Months Ended June 30, 2020		Six Months Ended June 30, 2020
	(In thousands)
Revenues	$	56,159	$	141,315
Expenses:
Operating costs	93,305		150,169
Depreciation, depletion and amortization	25,612		74,956
Impairment	109,318		787,280
Loss on abandonment of assets	—		17,554
General and administrative	25,814		37,367
Loss on disposition of assets	886		1,282
Total operating costs	254,935		1,068,608
Loss from operations	(198,776)		(927,293)
Other income (expense):
Interest, net	(7,066)		(19,805)
Write-off of debt issuance costs	(2,426)		(2,426)
Loss on derivatives	(6,937)		(6,454)
Reorganization items	(7,027)		(7,027)
Other, net	22		64
Total other income (expense)	(23,434)		(35,648)
Loss before income taxes	(222,210)		(962,941)
Income tax benefit	(6,455)		(9,880)
Equity in net earnings (losses) from investment	188		(66,178)
Net loss	(215,567)		(1,019,239)
Net income (loss) attributable to non-controlling interest	84		(33,096)
Net loss attributable to Unit Corp	$	(215,651)	$	(986,143)

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UNIT CORPORATION (DEBTOR-IN-POSSESSION)

Condensed Combined Statements of Cash Flows (Unaudited)


	Six Months Ended June 30, 2020
	(In thousands)
OPERATING ACTIVITIES:
Net loss	$	(1,019,239)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	74,956
Impairments	787,280
Loss on abandonment of assets	17,554
Amortization of debt issuance costs and debt discount	1,079
Equity investment in non-debtor subsidiaries	66,086
Loss on derivatives	6,454
Cash receipts on derivatives settled	(691)
Loss on disposition of assets	1,282
Write-off of debt issuance costs	2,426
Deferred tax benefit	(8,963)
Employee stock compensation plans	4,179
Bad debt expense	1,923
ARO liability accretion	1,169
Noncash reorganization items	7,027
Other, net	11,621
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	26,609
Material and supplies	43
Prepaid expenses and other	(3,158)
Accounts payable	(20,958)
Accrued liabilities	49,661
Net cash provided by operating activities	6,340
INVESTING ACTIVITIES:
Capital expenditures	(14,188)
Producing properties and other acquisitions	(210)
Proceeds from disposition of property and equipment	4,422
Net cash used in investing activities	(9,976)
FINANCING ACTIVITIES:
Borrowings under line of credit, including borrowings under DIP credit facility	47,300
Payments under line of credit	(23,500)
DIP financing costs	(990)
Intercompany borrowings	781
Employee taxes paid by withholding shares	(43)
Bank overdrafts	(7,269)
Net cash provided by financing activities	16,279
Net increase in cash and cash equivalents	12,643
Cash and cash equivalents, beginning of year	571
Cash and cash equivalents, end of year	$	13,214

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NOTE 3 – IMPAIRMENTS

We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of such 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 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 are a triggering event that requires 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. However, 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.

No triggering events were identified during the second quarter of 2020.

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 three and six months ended June 30, 2020.

Oil and Natural Gas Properties

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 unescalated 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.

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 resulted 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. During the second quarter of 2020, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of $109.3 million pre-tax. We had no non-cash ceiling test write-downs in the first six months of 2019.

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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 asset in the first quarter of 2020.

Contract Drilling

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 charges 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 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

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

NOTE 4 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is how we disaggregate our revenue and report our segment revenue (as reflected in Note 17 – 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 June 30, 2020, we had three 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.

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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 six months ended June 30, 2020:


	June 30, 2020		December 31, 2019		Change
	(In thousands)
Contract assets	$	9,695	$	12,921	$	(3,226)
Contract liabilities	5,625		7,061		(1,436)
Contract assets (liabilities), net	$	4,070	$	5,860	$	(1,790)

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.

Included below is the fixed revenue we will earn over the remaining term of the contracts and excludes all variable consideration to be earned with the associated contract.


Contract	Remaining Term of Contract	July - December 2020		2021		2022		2023 and beyond		Total Remaining Impact to Revenue
		(In thousands)
Demand fee contracts	2-8 years	$	(1,985)	$	(3,501)	$	1,380	$	36	$	(4,070)

NOTE 5 – DIVESTITURES

Oil and Natural Gas

We sold $0.9 million of non-core oil and natural gas assets, net of related expenses, during the first six months of 2020, compared to $2.1 million during the first six 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 throughout 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. We no longer have assets that meet the criteria to be classified as held for sale.

NOTE 6 – LOSS PER SHARE

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


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended June 30, 2020
Basic loss attributable to Unit Corporation per common share	$	(215,649)	53,503	$	(4.03)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(215,649)	53,503	$	(4.03)
For the three months ended June 30, 2019
Basic loss attributable to Unit Corporation per common share	$	(8,509)	52,930	$	(0.16)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(8,509)	52,930	$	(0.16)

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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
	June 30,
	2020		2019
Stock options	28,000		42,000
Average exercise price	$	52.24	$	48.56


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the six months ended June 30, 2020
Basic loss attributable to Unit Corporation per common share	$	(986,143)	53,317	$	(18.50)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(986,143)	53,317	$	(18.50)
For the six months ended June 30, 2019
Basic loss attributable to Unit Corporation per common share	$	(12,013)	52,744	$	(0.23)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(12,013)	52,744	$	(0.23)

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:


	Six Months Ended
	June 30,
	2020		2019
Stock options	28,000		42,000
Average exercise price	$	52.24	$	48.56

NOTE 7 – ACCRUED LIABILITIES

Accrued liabilities consisted of:


	June 30, 2020		December 31, 2019
	(In thousands)
Employee costs	$	7,016	$	17,832
Lease operating expenses	6,651		9,200
Taxes	6,343		3,450
Third-party credits	2,167		3,691
Derivative settlements	1,323		—
Interest payable	760		6,562
Other	7,124		5,827
Total accrued liabilities	$	31,384	$	46,562

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

Long-Term Debt

The company's filing of the Bankruptcy Petitions constituted an event of default that accelerated the company's obligations under the Unit credit agreement and the Notes. As a result of the filing of the Bankruptcy Petitions, subject to certain limited exceptions, the lenders under the Unit credit agreement and the holders of the Notes were stayed from taking any actions against the company.

As of the date indicated, our long-term debt, not including debt instruments classified as liabilities subject to compromise, consisted of the following:


	June 30, 2020		December 31, 2019
	(In thousands)
Current portion of long-term debt:
Unit credit agreement with an average interest rate of 2.3% and 4.0% at June 30, 2020 and December 31, 2019, respectively	$	124,000	$	108,200
DIP credit agreement with an average interest rate of 7.5% at June 30, 2020	8,000		—




Total current portion of long-term debt	132,000		108,200
Long-term debt:
Superior credit agreement with an average interest rate of 2.2% and 3.9% at June 30, 2020 and December 31, 2019, respectively	34,000		16,500
6.625% senior subordinated notes due 2021	—		650,000
Total principal amount	34,000		666,500
Less: unamortized discount	—		(971)
Less: debt issuance costs, net	—		(2,313)
Total long-term debt	$	34,000	$	663,216

Unit 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 Unit credit agreement is reflected as a current liability in its consolidated balance sheet as of June 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 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. Under the Unit 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 such oil and gas properties, UPC also pledged as collateral 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 Unit credit agreement.

Before filing the Chapter 11 Cases, any part of the outstanding debt under the Unit credit agreement could be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is 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 is payable at the end of each term, or every 90 days,

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whichever is less. Borrowings not under LIBOR bear interest equal to the higher of the prime rate specified in the Unit 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 shall the interest on such borrowings be less than LIBOR plus 1.00% plus a margin. The Unit 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, Administrative Agent may select a replacement index. Interest is 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.

On the Effective Date, each lender under the Unit 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 Unit credit facility or the DIP credit facility.

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 1.00%) 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 June 30, 2020, Superior complied with these covenants.

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

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

6.625% Senior Subordinated Notes. As of June 30, 2020, we had an aggregate principal amount of $650.0 million outstanding on the Notes. Interest on the Notes was payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes were scheduled to mature on May 15, 2021. In issuing the Notes, we incurred fees of $14.7 million that were being amortized as debt issuance cost until maturity. In the second quarter of 2020, we wrote off the remaining debt issuance costs of $2.2 million due to the filing of the Bankruptcy Petitions. The Notes plus accrued interest as of the Petition Date are included in liabilities subject to compromise in the condensed consolidated balance sheet as of June 30, 2020.

The Notes were subject to 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. On the Effective Date, by operation of the Plan, all outstanding obligations under the Notes were cancelled.

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Unit, other than its ownership in its subsidiaries, has no significant independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) were full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Superior was not a Guarantor of the Notes as of the Petition Date. Excluding Superior, any of our other subsidiaries that were not Guarantors were minor. There are no significant restrictions on our ability to receive funds from any subsidiary through dividends, loans, advances, or otherwise.

Filing of the Bankruptcy Petitions on May 22, 2020 constituted an event of default that accelerated the company’s obligations under the Notes. However, under the Bankruptcy Code, holders of the Notes were stayed from taking any action against the company or the other Debtors because of the default. Pursuant to the Plan, each holder of the Notes will receive 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.

On the Effective Date, by operation of the Plan, the Debtors' outstanding obligations under the Notes and the 2011 Indenture were cancelled.

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 new money 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. As of June 30, 2020, we had $8.0 million outstanding under 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 such holder was issued on the Effective Date (or will be issued 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 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern.

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Other Long-Term Liabilities

Other long-term liabilities consisted of the following:


	June 30, 2020		December 31, 2019
	(In thousands)
Asset retirement obligation (ARO) liability	$	64,248	$	66,627
Workers’ compensation	12,112		11,510
Finance lease obligations	5,319		7,379
Contract liability	5,625		7,061
Separation benefit plans ⁽¹⁾	—		10,122
Deferred compensation plan	6,006		6,180
Gas balancing liability	3,823		3,838
Other long-term liability	1,217		—
	98,350		112,717
Less current portion	13,628		17,376
Total other long-term liabilities	$	84,722	$	95,341

_______________________

1.The separation benefit plans are part of the liabilities subject to compromise as of June 30, 2020. For further information, please see Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern.

Estimated annual principal payments under the terms of our long-term debt and other long-term liabilities during the five successive twelve-month periods beginning July 1, 2020 (and through 2024) are $145.6 million, $5.6 million, $2.8 million, $36.2 million, and $2.3 million, respectively. 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 June 30, 2020.

NOTE 9 – ASSET RETIREMENT OBLIGATIONS

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

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


	Six Months Ended
	June 30,
	2020		2019
	(In thousands)
ARO liability, January 1:	$	66,627	$	64,208
Accretion of discount	1,169		1,168
Liability incurred	460		3,656
Liability settled	(435)		(2,316)
Liability sold	(463)		(1,632)
Revision of estimates ⁽¹⁾	(3,110)		2,349
ARO liability, June 30:	64,248		67,433
Less current portion	1,104		1,784
Total long-term ARO	$	63,144	$	65,649

_______________________

1.Plugging liability estimates were revised in both 2020 and 2019 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

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NOTE 10 – NEW ACCOUNTING PRONOUNCEMENTS

Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued 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 amendment will be in effect for a limited time through December 31, 2022.

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. The amendment is 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 is 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 11 – STOCK-BASED COMPENSATION

On the Effective Date, our equity-based awards outstanding immediately before the Effective Date were cancelled. Under the Plan, Warrants will be issued to holders of the equity-based awards outstanding immediately before the Effective Date if the holder did not opt out of the releases under the Plan. We expect to issue the warrants during the fourth quarter of 2020.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
	(In millions)
Recognized stock compensation expense	$	1.6	$	4.7	$	4.1	$	8.5
Capitalized stock compensation cost for our oil and natural gas properties	—		0.7		—		1.3
Tax benefit on stock-based compensation	0.4		1.2		1.0		2.1

The remaining unrecognized compensation cost related to unvested awards as of June 30, 2020 is approximately $5.7 million. The weighted average period over which this cost will be recognized is 1.1 years.

Our Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) and to non-employee directors. There are 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 can be issued as "incentive stock options."

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


	Three Months Ended
	June 30, 2019
	Time Vested			Performance Vested
Shares granted:
Employees	1,500			—
Non-employee directors	72,784			—
	74,284			—
Estimated fair value (in millions):⁽¹⁾
Employees	$	—		$	—
Non-employee directors	0.9			—
	$	0.9		$	—
Percentage of shares granted expected to be distributed:
Employees	95		%	N/A
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.)


	Six Months Ended
	June 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		%	54		%
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 six months of 2019 are 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%. Based on a probability assessment of the selected TSR performance criteria at June 30, 2020, the participants are not expected to receive any performance-based shares. We expense the CFTA performance award at target or 100%.

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NOTE 12 – DERIVATIVES

Commodity Derivatives

We have signed various types of derivative transactions covering some of our projected natural gas and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of June 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.

•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.

•Three-way collars. A three-way collar contains a fixed floor price (long put), fixed subfloor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, we receive the ceiling strike price and pay the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the subfloor price, we receive the floor strike price and pay the market price. If the market price is below the subfloor price, we receive the market price plus the difference between the floor and subfloor strike prices and pay the market price.

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.

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

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Jul'20 - Dec'20

Natural gas - basis swap

30,000 MMBtu/day

$(0.275)

NGPL TEXOK

Jul'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

Jul'20 - Dec'20

Natural gas - three-way collar

30,000 MMBtu/day

$2.50 - $2.20 - $2.80

IF - NYMEX (HH)

Jul'20 - Sep'20

Crude oil - collar

112,000 Bbl/month

$20.00 - $26.50

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
	Balance Sheet Location	June 30, 2020		December 31, 2019
		(In thousands)
Commodity derivatives:
Current	Current derivative asset	$	—	$	633
Long-term	Non-current derivative asset	—		—
Total derivative assets		$	—	$	633

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		Derivative Liabilities
		Fair Value
	Balance Sheet Location	June 30, 2020		December 31, 2019
		(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	5,011	$	—
Long-term	Non-current derivative liability	145		27
Total derivative liabilities		$	5,156	$	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.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
	(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of ($1,243), $2,658, ($691), and $5,314, respectively	$	(6,937)	$	7,927	$	(6,454)	$	995
	$	(6,937)	$	7,927	$	(6,454)	$	995

The commencement of the Chapter 11 Cases constituted a termination event with respect to the company’s derivative instruments, which permits the counterparties to such derivative instruments to terminate their outstanding hedges. Such terminations are not stayed under the Bankruptcy Code. However, none of the company’s counterparties elected to terminate outstanding hedges based on the occurrence of this termination event (or otherwise).

NOTE 13 – 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:


	June 30, 2020
	Level 2		Level 3		Effect of Netting		Net Amounts Presented

Financial assets (liabilities):
Commodity derivatives:
Assets	$	—	$	843	$	(843)	$	—
Liabilities	(5,999)		—		843		(5,156)
Total commodity derivatives	$	(5,999)	$	843	$	—	$	(5,156)


	December 31, 2019
	Level 2		Level 3		Effect of Netting		Net Amounts Presented

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 June 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
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
	(In thousands)
Beginning of period	$	948	$	3,080	$	1,204	$	10,630
Total gains or losses (realized and unrealized):
Included in earnings ⁽¹⁾	714		2,060		1,277		(3,374)
Settlements	(819)		(1,195)		(1,638)		(3,311)
End of period	$	843	$	3,945	$	843	$	3,945
Total earnings (losses) for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period	$	(105)	$	865	$	(361)	$	(6,685)

_______________________

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

The following table provides quantitative information about our Level 3 unobservable inputs at June 30, 2020:

Commodity ⁽¹⁾

Fair Value

Valuation Technique

Unobservable Input

Range

(In thousands)

Natural gas three-way collars

843

Discounted cash flow

Forward commodity price curve

$0.00 - $0.75

_______________________

1.The commodity contracts detailed in this category include non-exchange-traded natural gas three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Our valuation at June 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 June 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. As of June 30, 2020, the Notes are classified as liabilities subject to compromise in the Unaudited Condensed Consolidated Balance Sheets as of June 30, 2020. The estimated fair value of the Notes using quoted market prices at June 30, 2020 and December 31, 2019 was $100.4 million and $357.5 million, respectively. The Notes would be 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 9 – Asset Retirement Obligations.

NOTE 14 – 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

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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. As of June 30, 2020, we had an average working interest of 97% in our operated properties.

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


	Six Months Ended
	June 30, 2020		June 30, 2019
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	2,827	$	1,616
Financing cash flows for finance leases	2,061		1,980
Lease liabilities recognized in exchange for new operating lease right of use assets	—		5

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


	Classification on the Consolidated Balance Sheets	June 30, 2020		December 31, 2019
		(In thousands)
Assets
Operating right of use assets	Right of use assets	$	7,828	$	5,673
Finance right of use assets	Property, plant, and equipment, net	16,455		17,396
Total right of use assets		$	24,283	$	23,069

Liabilities
Current liabilities:
Operating lease liabilities	Current operating lease liabilities	$	4,666	$	3,430
Finance lease liabilities	Current portion of other long-term liabilities	5,157		4,164
Non-current liabilities:
Operating lease liabilities	Operating lease liabilities	3,012		2,071
Finance lease liabilities	Other long-term liabilities	162		3,215
Total lease liabilities		$	12,997	$	12,880

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



	Three Months Ended						Six Months Ended
	June 30, 2020		June 30, 2019		June 30, 2020		June 30, 2019
	(In thousands)
Components of total lease cost:
Amortization of finance leased assets	$	1,036	$	995	$	2,061	$	1,980
Interest on finance lease liabilities	60		100		130		211
Operating lease cost	1,395		1,052		2,639		1,651
Short-term lease cost, included are amounts capitalized related to our oil and natural gas segment of $0.4 million, $9.0 million, $1.4 million, and $14.7 million, respectively	2,751		12,038		6,742		22,012
Variable lease cost	83		84		165		190
Total lease cost	$	5,325	$	14,269	$	11,737	$	26,044

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	4.81%
Finance leases	1.2	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 June 30, 2020:


	Amount
	(In thousands)
Ending July 1,
2021	$	4,938
2022	2,786
2023	222
2024	23
2025	12
2025 and beyond	70
Total future payments	8,051
Less: Interest	373
Present value of future minimum operating lease payments	7,678
Less: Current portion	4,666
Total long-term operating lease payments	$	3,012

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 $5.2 million current portion of the finance lease obligations is included in current portion of other long-term liabilities and the non-current portion of $0.2 million is included in

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other long-term liabilities in the Unaudited Condensed Consolidated Balance Sheets as of June 30, 2020. These finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $1.4 million and $0.1 million, respectively, at June 30, 2020. Annual payments, net of maintenance and interest, average $4.6 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 June 30, 2020:


	Amount
Ending July 1,	(In thousands)
2020	$	6,692
2021	179
Total future payments	6,871
Less payments related to:
Maintenance	1,430
Interest	122
Present value of future minimum finance lease payments	5,319
Less: Current portion	5,157
Total long-term finance lease payments	$	162

NOTE 15 – 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. For further information on the Chapter 11 Cases, please see Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern.

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 any 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 that commits 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 50% ownership interest in our consolidated mid-stream subsidiary. At June 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. We have no plans to drill in 2020. Total spent towards the $150.0 million as of June 30, 2020 was $24.8 million.

We have firm transportation commitments to transport our natural gas from various systems for approximately $1.0 million over the next twelve months and $0.6 million for the 18 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. The company’s exploration and development subsidiary, Unit Petroleum Company, is a defendant in three royalty class action lawsuits. Below is a summary of two of those lawsuits and the respective treatment of those cases in the Bankruptcy Proceedings.

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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 two of the three class actions described in Item 1 – Legal Proceedings of Part II of this quarterly report. 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 16 – VARIABLE INTEREST ENTITY ARRANGEMENTS

On April 3, 2018 we sold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor 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 ("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. Unit through the MSA has the power to direct Superior’s most significant activities; reciprocally the equity investors lack the power to direct the activities that most affect the entity’s economic performance. Because of this, Unit is considered the primary beneficiary. There have been no changes to the primary beneficiary during the quarter ended June 30, 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.

On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements.

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 fulfil the drilling commitment described in Note 15 – 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

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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 . At June 30, 2020, if Superior were to be liquidated for its carrying value of assets and liabilities disclosed below and the liquidating distribution made to the partners, we estimate approximately 100% of that liquidating distribution would be distributed to SP Investor Holdings, LLC and nothing would be distributed to Unit based upon the 7% Liquidation IRR Hurdle. At June 30, 2020, a Sales Event resulting in proceeds of approximately $696.6 million would be required to result in equal liquidation distributions being made to SP Investor Holdings, LLC and Unit after application of the 7% Liquidation IRR Hurdle.

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.

The carrying value of Superior's assets and liabilities, after eliminations of any intercompany transactions and balances, in the consolidated balance sheets were as follows:


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

Current assets:
Cash and cash equivalents	$	23,780	$	—
Accounts receivable	18,718		21,073
Prepaid expenses and other	7,321		7,686
Total current assets	49,819		28,759
Property and equipment:
Gas gathering and processing equipment	833,402		824,699
Transportation equipment	3,363		3,390
	836,765		828,089
Less accumulated depreciation, depletion, amortization, and impairment	493,386		407,144
Net property and equipment	343,379		420,945
Right of use asset	4,542		3,948
Other assets	6,054		9,442
Total assets	$	403,794	$	463,094

Current liabilities:
Accounts payable	$	9,980	$	18,511
Accrued liabilities	4,648		4,198
Current operating lease liability	2,518		2,407
Current portion of other long-term liabilities	8,059		7,060
Total current liabilities	25,205		32,176
Long-term debt	34,000		16,500
Operating lease liability	1,911		1,404
Other long-term liabilities	3,811		8,126
Total liabilities	$	64,927	$	58,206

NOTE 17 – 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

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•Mid-stream.

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

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

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


	Three Months Ended June 30, 2020
	Oil and Natural Gas		Contract Drilling		Mid-stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: ⁽¹⁾
Oil and natural gas	$	26,957	$	—	$	—	$	—	$	(1)	$	26,956
Contract drilling	—		29,202		—		—		—		29,202
Gas gathering and processing	—		—		37,719		—		(4,870)		32,849
Total revenues	26,957		29,202		37,719		—		(4,871)		89,007
Expenses:
Operating costs:
Oil and natural gas	72,354		—		—		—		(814)		71,540
Contract drilling	—		20,951		—		—		—		20,951
Gas gathering and processing	—		—		26,669		—		(4,057)		22,612
Total operating costs	72,354		20,951		26,669		—		(4,871)		115,103
Depreciation, depletion, and amortization	22,059		2,946		10,348		607				35,960
Impairments	109,318		—		—		—		—		109,318
Total expenses	203,731		23,897		37,017		607		(4,871)		260,381

General and administrative	—		—		—		25,814		—		25,814
(Gain) loss on disposition of assets	(45)		(548)		(9)		1,479		—		877
Income (loss) from operations	(176,729)		5,853		711		(27,900)		—		(198,065)
Loss on derivatives	—		—		—		(6,937)		—		(6,937)
Write-off of debt issuance costs	—		—		—		(2,426)		—		(2,426)
Reorganization items	—		—		—		(7,027)		—		(7,027)
Interest, net	—		—		(542)		(7,066)		—		(7,608)
Other	9		6		22		6		—		43
Income (loss) before income taxes	$	(176,720)	$	5,859	$	191	$	(51,350)	$	—	$	(222,020)

_______________________

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

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	Three Months Ended June 30, 2019
	Oil and Natural Gas		Contract Drilling		Mid-stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: ⁽¹⁾
Oil and natural gas	$	77,815	$	—	$	—	$	—	$	—	$	77,815
Contract drilling	—		50,773		—		—		(7,736)		43,037
Gas gathering and processing	—		—		54,630		—		(10,336)		44,294
Total revenues	77,815		50,773		54,630		—		(18,072)		165,146
Expenses:
Operating costs:
Oil and natural gas	37,519		—		—		—		(1,277)		36,242
Contract drilling	—		36,390		—		—		(7,082)		29,308
Gas gathering and processing	—		—		41,550		—		(9,059)		32,491
Total operating costs	37,519		36,390		41,550		—		(17,418)		98,041
Depreciation, depletion, and amortization	38,751		13,504		12,102		1,935		—		66,292
Total expenses	76,270		49,894		53,652		1,935		(17,418)		164,333
General and administrative	—		—		—		10,064		—		10,064
Gain on disposition of assets	(60)		(296)		(66)		—		—		(422)
Income (loss) from operations	1,605		1,175		1,044		(11,999)		(654)		(8,829)
Gain on derivatives	—		—		—		7,927		—		7,927
Interest, net	—		—		(345)		(8,650)		—		(8,995)
Other	—		—		—		6		—		6
Income (loss) before income taxes	$	1,605	$	1,175	$	699	$	(12,716)	(654)		$	(9,891)

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

_______________________ ____________________

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

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	Six Months Ended June 30, 2019
	Oil and Natural Gas			Contract Drilling		Mid-stream		Corporate and Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: ⁽¹⁾
Oil and natural gas	$	163,910		$	—	$	—	$	—	$	—	$	163,910
Contract drilling	—			108,972		—		—		(14,780)		94,192
Gas gathering and processing	—			—		125,139		—		(28,404)		96,735
Total revenues	163,910			108,972		125,139		—		(43,184)		354,837
Expenses:
Operating costs:
Oil and natural gas	71,527			—		—		—		(2,571)		68,956
Contract drilling	—			73,775		—		—		(13,066)		60,709
Gas gathering and processing	—			—		97,679		—		(25,833)		71,846
Total operating costs	71,527			73,775		97,679		—		(41,470)		201,511
Depreciation, depletion, and amortization	74,518			26,203		23,828		3,869		—		128,418
Total expenses	146,045			99,978		121,507		3,869		(41,470)		329,929
General and administrative	—			—		—		19,805		—		19,805
(Gain) loss on disposition of assets	(138)		-84	1,449		(108)		(10)		—		1,193
Income (loss) from operations	18,003			7,545		3,740		(23,664)		(1,714)		3,910
Gain on derivatives	—			—		—		995		—		995
Interest, net	—			—		(681)		(16,852)		—		(17,533)
Other	—			—		—		11		—		11
Income (loss) before income taxes	$	18,003		$	7,545	$	3,059	(39,510)		$	(1,714)	$	(12,617)

_______________________

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 18 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have no significant assets or operations other than our investments in our subsidiaries. Our wholly owned subsidiaries are the guarantors of our Notes. On April 3, 2018, we sold 50% of the ownership interest in our mid-stream segment, Superior and that company and its subsidiaries are no longer guarantors of the Notes. Instead of providing separate financial statements for each subsidiary issuer and guarantor, we have included the unaudited condensed consolidating financial statements based on Rule 3-10 of the SEC's Regulation S-X.

For the following footnote:

•we are called "Parent",

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

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

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

Table of Contents

Condensed Consolidating Balance Sheets (Unaudited)


	June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	13,214	$	—	$	23,780	$	—	$	36,994
Accounts receivable, net of allowance for doubtful accounts of $3,961 (Guarantor of $2,745 and Parent of $1,216)	1,702		37,216		20,518		(5,290)		54,146
Materials and supplies	—		110		—		—		110

Income taxes receivable	850		—		—		—		850
Prepaid expenses and other	6,575		2,763		7,321		—		16,659
Total current assets	22,341		40,089		51,619		(5,290)		108,759
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties	—		6,566,669		—		—		6,566,669
Unproved properties not being amortized	—		30,342		—		—		30,342
Drilling equipment	—		1,296,319		—		—		1,296,319
Gas gathering and processing equipment	—		—		833,402		—		833,402
Saltwater disposal systems	—		43,843		—		—		43,843
Corporate land and building	—		59,080		—		—		59,080
Transportation equipment	362		13,055		3,363		—		16,780
Other	29,005		29,031		—		—		58,036
	29,367		8,038,339		836,765		—		8,904,471
Less accumulated depreciation, depletion, amortization, and impairment	27,888		7,381,777		493,386		—		7,903,051
Net property and equipment	1,479		656,562		343,379		—		1,001,420
Intercompany receivable	853,800		—		—		(853,800)		—
Investments	15,106		—		—		(15,106)		—

Right of use asset	34		3,303		4,542		(51)		7,828
Other assets	6,001		10,316		6,054		—		22,371
Total assets	$	898,761	$	710,270	$	405,594	$	(874,247)	$	1,140,378

Table of Contents


	June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,386	$	18,018	$	9,980	$	(2,576)	$	26,808
Accrued liabilities	14,267		12,876		6,029		(1,788)		31,384
Current operating lease liability	18		2,136		2,518		(6)		4,666
Current portion of long-term debt	124,000		—		—		—		124,000
Debtor-in-possession financing	8,000		—		—		—		8,000
Current derivative liability	5,011		—		—		—		5,011
Current portion of other long-term liabilities	—		5,615		8,059		(46)		13,628
Total current liabilities	152,682		38,645		26,586		(4,416)		213,497
Intercompany debt	—		853,491		309		(853,800)		—
Long-term debt	—		—		34,000		—		34,000
Non-current derivative liability	145		—		—		—		145
Operating lease liability	16		1,130		1,911		(45)		3,012
Other long-term liabilities	6,124		75,499		3,979		(880)		84,722
Liabilities subject to compromise	694,512		65,208		—		—		759,720
Deferred income taxes	4,750		—		—		—		4,750









Total shareholders’ equity	40,532		(323,703)		338,809		(15,106)		40,532
Total liabilities and shareholders’ equity	$	898,761	$	710,270	$	405,594	$	(874,247)	$	1,140,378

Table of Contents


	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

Table of Contents


	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

Table of Contents

Condensed Consolidating Statements of Operations (Unaudited)


	Three Months Ended June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	56,159	$	37,719	$	(4,871)	$	89,007
Expenses:
Operating costs	—		93,305		26,671		(4,873)		115,103
Depreciation, depletion, and amortization	607		25,005		10,348		—		35,960
Impairments	—		109,318		—		—		109,318

General and administrative	—		25,814		—		—		25,814
(Gain) loss on disposition of assets	1,479		(593)		(9)		—		877
Total operating costs	2,086		252,849		37,010		(4,873)		287,072
Income (loss) from operations	(2,086)		(196,690)		709		2		(198,065)
Interest, net	(7,066)		—		(542)		—		(7,608)
Write off of debt issuance costs	(2,426)		—		—		—		(2,426)
Loss on derivatives	(6,937)		—		—		—		(6,937)
Reorganization items	(2,205)		(4,822)		—		—		(7,027)
Other, net	4		18		21		—		43
Income (loss) before income taxes	(20,716)		(201,494)		188		2		(222,020)
Income tax benefit	(6,455)		—		—		—		(6,455)
Equity in net earnings from investment in subsidiaries, net of taxes	(201,304)		—		—		201,304		—
Net income (loss)	(215,565)		(201,494)		188		201,306		(215,565)
Less: net income attributable to non-controlling interest	84		—		84		(84)		84
Net income (loss) attributable to Unit Corporation	$	(215,649)	$	(201,494)	$	104	$	201,390	$	(215,649)


	Three Months Ended June 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	128,588	$	54,630	$	(18,072)	$	165,146
Expenses:
Operating costs	—		73,909		41,550		(17,418)		98,041
Depreciation, depletion, and amortization	1,935		52,255		12,102		—		66,292
General and administrative	—		10,064		—		—		10,064
Gain on disposition of assets	—		(356)		(66)		—		(422)
Total operating costs	1,935		135,872		53,586		(17,418)		173,975
Income (loss) from operations	(1,935)		(7,284)		1,044		(654)		(8,829)
Interest, net	(8,650)		—		(345)		—		(8,995)
Gain on derivatives	7,927		—		—		—		7,927
Other, net	6		—		—		—		6
Income (loss) before income taxes	(2,652)		(7,284)		699		(654)		(9,891)
Income tax benefit	(848)		(1,026)		—		—		(1,874)
Equity in net earnings from investment in subsidiaries, net of taxes	(6,705)		—		—		6,705		—
Net income (loss)	(8,509)		(6,258)		699		6,051		(8,017)
Less: net income attributable to non-controlling interest	—		—		492		—		492
Net income (loss) attributable to Unit Corporation	$	(8,509)	$	(6,258)	$	207	$	6,051	$	(8,509)

Table of Contents


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


	Six Months Ended June 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	272,882	$	125,139	$	(43,184)	$	354,837
Expenses:
Operating costs	—		145,302		97,679		(41,470)		201,511
Depreciation, depletion, and amortization	3,869		100,721		23,828		—		128,418
General and administrative	—		19,805		—		—		19,805
(Gain) loss on disposition of assets	(10)		1,311		(108)		—		1,193
Total operating costs	3,859		267,139		121,399		(41,470)		350,927
Income (loss) from operations	(3,859)		5,743		3,740		(1,714)		3,910
Interest, net	(16,852)		—		(681)		—		(17,533)
Gain on derivatives	995		—		—		—		995
Other, net	11		—		—		—		11
Income (loss) before income taxes	(19,705)		5,743		3,059		(1,714)		(12,617)
Income tax expense (benefit)	(4,547)		2,229		—		—		(2,318)
Equity in net earnings from investment in subsidiaries, net of taxes	3,145		—		—		(3,145)		—
Net income (loss)	(12,013)		3,514		3,059		(4,859)		(10,299)
Less: net income attributable to non-controlling interest	—		—		1,714		—		1,714
Net income (loss) attributable to Unit Corporation	$	(12,013)	$	3,514	$	1,345	$	(4,859)	$	(12,013)

Table of Contents

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


	Three Months Ended June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net income (loss)	$	(215,565)	$	(201,494)	$	188	$	201,306	$	(215,565)
Other comprehensive income (loss), net of taxes:
Unrealized gain on securities, net of tax of $0	—		—		—		—		—
Comprehensive income (loss)	(215,565)		(201,494)		188		201,306		(215,565)
Less: Comprehensive income attributable to non-controlling interests	84		—		84		(84)		84
Comprehensive income (loss) attributable to Unit Corporation	$	(215,649)	$	(201,494)	$	104	$	201,390	$	(215,649)


	Three Months Ended June 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net income (loss)	$	(8,509)	$	(6,258)	$	699	$	6,051	$	(8,017)
Other comprehensive income (loss), net of taxes:
Unrealized loss on securities, net of tax of ($9)	—		(30)		—		—		(30)
Comprehensive income (loss)	(8,509)		(6,288)		699		6,051		(8,047)
Less: Comprehensive income attributable to non-controlling interests	—		—		492		—		492
Comprehensive income (loss) attributable to Unit Corporation	$	(8,509)	$	(6,288)	$	207	$	6,051	$	(8,539)


	Six Months Ended June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net loss	$	(1,019,239)	$	(929,105)	$	(66,178)	$	995,283	$	(1,019,239)
Other comprehensive loss, net of taxes:
Unrealized gain on securities, net of tax of $0	—		—		—		—		—
Comprehensive loss	(1,019,239)		(929,105)		(66,178)		995,283		(1,019,239)
Less: Comprehensive loss attributable to non-controlling interests	(33,096)		—		(33,096)		33,096		(33,096)
Comprehensive loss attributable to Unit Corporation	$	(986,143)	$	(929,105)	$	(33,082)	$	962,187	$	(986,143)


	Six Months Ended June 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net income (loss)	$	(12,013)	$	3,514	$	3,059	$	(4,859)	$	(10,299)
Other comprehensive income (loss), net of taxes:
Unrealized loss on securities, net of tax of ($2)	—		(6)		—		—		(6)
Comprehensive income (loss)	(12,013)		3,508		3,059		(4,859)		(10,305)
Less: Comprehensive income attributable to non-controlling interests	—		—		1,714		—		1,714
Comprehensive income (loss) attributable to Unit Corporation	$	(12,013)	$	3,508	$	1,345	$	(4,859)	$	(12,019)

Table of Contents

Condensed Consolidating Statements of Cash Flows (Unaudited)


	Six Months Ended June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(201,699)	$	59,486	$	20,117	$	148,563	$	26,467
INVESTING ACTIVITIES:
Capital expenditures	(760)		(13,428)		(9,616)		—		(23,804)
Producing properties and other acquisitions	—		(210)		—		—		(210)
Proceeds from disposition of assets	1,169		3,253		75		—		4,497
Net cash provided by (used in) investing activities	409		(10,385)		(9,541)		—		(19,517)
FINANCING ACTIVITIES:
Borrowings under credit agreement, including borrowings under DIP credit facility	47,300		—		32,100		—		79,400
Payments under credit agreement	(23,500)		—		(14,600)		—		(38,100)
DIP financing costs	(990)		—		—		—		(990)
Intercompany borrowings (advances), net	198,503		(49,169)		(771)		(148,563)		—
Payments on finance leases	—		—		(2,061)		—		(2,061)
Employee taxes paid by withholding shares	(43)		—		—		—		(43)
Bank overdrafts	(7,269)		—		(1,464)		—		(8,733)
Net cash provided by (used in) financing activities	214,001		(49,169)		13,204		(148,563)		29,473
Net increase (decrease) in cash and cash equivalents	12,711		(68)		23,780		—		36,423
Cash and cash equivalents, beginning of period	503		68		—		—		571
Cash and cash equivalents, end of period	$	13,214	$	—	$	23,780	$	—	$	36,994


	Six Months Ended June 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	$	(8,023)	$	111,615	$	23,943	$	(34)	$	127,501
INVESTING ACTIVITIES:
Capital expenditures	(100)		(212,982)		(33,556)		—		(246,638)
Producing properties and other acquisitions	—		(3,313)		—		—		(3,313)
Proceeds from disposition of assets	10		7,247		83		—		7,340
Net cash used in investing activities	(90)		(209,048)		(33,473)		—		(242,611)
FINANCING ACTIVITIES:
Borrowings under credit agreement	238,800		—		32,400		—		271,200
Payments under credit agreement	(135,300)		—		(24,900)		—		(160,200)
Intercompany borrowings (advances), net	(96,311)		97,384		(1,107)		34		—
Payments on finance leases	—		—		(1,980)		—		(1,980)
Employee taxes paid by withholding shares	(4,073)		—		—		—		(4,073)
Distributions to non-controlling interest	919		—		(1,837)		—		(918)
Bank overdrafts	4,183		—		1,115		—		5,298
Net cash provided by financing activities	8,218		97,384		3,691		34		109,327
Net increase (decrease) in cash and cash equivalents	105		(49)		(5,839)		—		(5,783)
Cash and cash equivalents, beginning of period	403		208		5,841		—		6,452
Cash and cash equivalents, end of period	$	508	$	159	$	2	$	—	$	669

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NOTE 19 – SUBSEQUENT EVENTS

Emergence from Bankruptcy

On May 22, 2020, the Debtors filed the Bankruptcy Petitions seeking relief under the Bankruptcy Code. In accordance with the RSA, the Debtors filed the Plan and the related disclosure statement with the Bankruptcy Court on June 9, 2020. On August 6, 2020, the Bankruptcy Court entered the Confirmation Order confirming the Plan and approving the disclosure statement on a final basis. On the Effective Date, the company emerged from the Chapter 11 Cases after satisfying or waiving the remaining conditions to effectiveness contemplated under the Plan.

On August 21, 2020, the Debtors agreed, subject to Bankruptcy Court approval, to settle the claims asserted in two class action lawsuits that are stayed as a result of the Chapter 11 Cases. For the lawsuit styled as Cockerell Oil Properties, Ltd. v. Unit Petroleum Company, the Debtors agreed to settle for an allowed claim amount of $15.75 million and for the lawsuit styled as Chieftain Royalty Company v. Unit Petroleum Company, the Debtors agreed to settle for an allowed claim amount of $29.25 million. Both settled claims will be treated as general unsecured claims and the holders will receive their pro rata share of the common stock of reorganized Unit (New Common Stock) allocated to holders of general unsecured claims against UPC, as set forth in the Plan.

Termination of Deferred Compensation Plan

On August 7, 2020, we elected to terminate our salary deferral plan effective on emergence from bankruptcy. We reported these obligations in other long-term liabilities and the underlying investment accounts as other long-term assets in our Unaudited Condensed Consolidated Balance Sheets. The total amount due to plan participants as of June 30, 2020 was $6.0 million. These amounts were subsequently distributed to the plan participants.

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 in conjunction with 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. (Superior) of which we own 50%.

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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 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

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, 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 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.

On May 22, 2020, the Debtors entered into a Restructuring Support Agreement (RSA) with (i) holders of 100% of the aggregate principal amount of loans outstanding under the Senior Credit Agreement, dated as of September 13, 2011 (as amended, the Unit credit agreement, together with the loan facility, the Unit credit facility), by and among the company, UPC and UDC, as borrowers, the institutions named as lenders (RBL Lenders) and BOKF, NA dba Bank of Oklahoma, as administrative agent (RBL Agent) and (ii) holders of over 70% of the aggregate outstanding principal amount of the company’s 6.625% senior subordinated notes due 2021 (Notes). In accordance with the RSA, 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 Debtors’ Chapter 11 plan of reorganization (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 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern.

Going Concern and Financial Reporting in Reorganization

In addition to reorganizing our capital structure in the Chapter 11 Cases, we have taken several actions to alleviate the conditions that cause substantial doubt about our ability to continue as a going concern, including (i) minimizing capital expenditures, (ii) aggressively managing working capital, (iii) further reducing recurring operating expenses, and (iv) exploring potential business transactions. However, the significant risks and uncertainties related to the company’s liquidity and Chapter 11 Cases at June 30, 2020 raised substantial doubt about the company’s ability to continue as a going concern. The company, therefore, concluded as of such date there continues to be substantial doubt about the company’s ability to continue as a going concern.

The condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements include no adjustments that might result from the outcome of the going concern uncertainty. If the company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

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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 filing of the Chapter 11 Cases. Effective May 27, 2020, trades in our common stock began being quoted on the OTC Pink Market under the symbol “UNTCQ”. 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 Unit common stock outstanding immediately before the Effective Date were cancelled. We are currently seeking to facilitate trading of the New Common Stock of Unit issued under the Plan on one of the OTC markets. We expect to complete this process and issue the New Common Stock and the warrants during the fourth quarter of 2020.

Business Outlook

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.

The global spread of COVID-19 has caused widespread illness and significant loss of life, leading governments across the world to impose stringent limitations on movement and human interaction. The response of governments throughout the world to address the spread of COVID-19, including, among other actions, imposing travel bans, quarantines and entry restrictions, has significantly slowed down the global economic activity and reduced the demand for oil and natural gas. We can neither predict the duration nor estimate the economic impact of the COVID-19 pandemic. Therefore, the company can give no assurances that the spread of COVID-19 will not have a material adverse effect on its financial position or results of operations in 2020 and beyond. 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.

Exacerbating the reduced demand caused by the COVID-19 pandemic, in March, 2020, the price of oil fell approximately 20% due to a dispute over production levels between Saudi Arabia and Russia. Saudi Arabia’s subsequent decision to dramatically increase its oil production and engage in a price war with Russia led to a massive oversupply of oil, which flooded the global markets. The confluence of the spread of COVID-19 and the oil price war significantly impacted the oil and gas industry, causing an unprecedented drop in oil prices and ensuing reductions of exploration and production company capital and operating budgets. On April 12, 2020, 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, on July 15, 2020, 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 half 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:

_________________________

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

For the six months ended June 30, 2020, we participated in completing 27 gross wells (6.16 net wells) drilled by other operators. For 2020, we do not currently have any plans to drill wells pending our ability to refinance our debt and the outcome of the Restructuring.

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In the first six months of 2020, we incurred a non-cash ceiling test write-down of our oil and natural gas properties of $377.2 million pre-tax ($330.1 million net of tax). 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. We anticipate a non-cash ceiling test write-down in the third quarter of 2020 before re-emergence from bankruptcy in our predecessor company using 12-month average prices as of August 2020. We will be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, and those values may materially change relative to our historical consolidated financial statements.

During the first quarter of 2020, in addition to the impairment evaluations of our proved and unproved oil and gas properties, we also evaluated the carrying value of our salt water disposal assets. As a result of our revised forecast of asset utilization, we determined certain assets were no longer expected to be utilized and wrote off certain salt water disposal assets that we 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. We did not have a write-down in the second quarter 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 did not have an impairment in the second quarter of 2020.

Within our mid-stream segment, 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 during the first quarter of 2020. These charges are included within impairment charges in our Consolidated Statement of Operations. We did not have an impairment in the second quarter of 2020.

Executive Summary

Oil and Natural Gas

Second quarter 2020 production from our oil and natural gas segment was 3,004,000 barrels of oil equivalent (Boe), a decrease of 13% from the first quarter of 2020 and a decrease of 28% from the second quarter of 2019. The decreases came from fewer net wells being completed in the last nine months to replace declines in existing drilled wells.

Second quarter 2020 oil and natural gas revenues decreased 44% from the first quarter of 2020 and decreased 65% from the second quarter of 2019. The decreases were primarily from a decrease in commodity prices and production.

Our oil prices for the second quarter of 2020 decreased 53% from the first quarter of 2020 and decreased 65% from the second quarter of 2019. Our NGLs prices increased 26% over the first quarter of 2020 and decreased 67% from the second quarter of 2019. Our natural gas prices decreased 12% from the first quarter of 2020 and decreased 42% from the second quarter of 2019.

Operating cost per Boe produced for the second quarter of 2020 increased 167% over the first quarter of 2020 and increased 173% over the second quarter of 2019. The increases were primarily due a $45.0 million estimated litigation settlement partially offset by lower production applied against fixed costs and no G&G cost capitalized in the first half of 2020.

At June 30, 2020, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Jul'20 - Dec'20

Natural gas - basis swap

30,000 MMBtu/day

$(0.275)

NGPL TEXOK

Jul'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

Jul'20 - Dec'20

Natural gas - three-way collar

30,000 MMBtu/day

$2.50 - $2.20 - $2.80

IF - NYMEX (HH)

Jul'20 - Sep'20

Crude oil - collar

112,000 Bbl/month

$20.00 - $26.50

WTI - NYMEX

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After June 30, 2020, these derivatives were entered into:

Term

Commodity

Contracted Volume

Weighted Average Fixed Price

Contracted Market

Sep'20 - Dec'20

Natural gas - swap

10,000 MMBtu/day

$2.72

IF - NYMEX (HH)

Sep'20 - Oct'21

Natural gas - swap

20,000 MMBtu/day

$2.77

IF - NYMEX (HH)

Jan'21 - Oct'21

Natural gas - swap

30,000 MMBtu/day

$2.85

IF - NYMEX (HH)

Nov'21 - Dec'21

Natural gas - swap

45,000 MMBtu/day

$2.90

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - 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

After June 30, 2020, we converted the natural gas three-way collars into two-way collars by repurchasing the sold puts ($2.20 strike prices) and paying the current fair value for those puts.

As a result of the commencement of the Chapter 11 Cases, our ability to enter into derivative transactions is limited.

For the six months ended June 30, 2020, we participated in the completion of 27 gross wells (6.16 net wells) drilled by other operators. For 2020, we do not currently have any plans to drill wells pending our ability to refinance our debt.

Contract Drilling

The average number of drilling rigs we operated in the second quarter of 2020 was 9.1 compared to 18.7 and 28.6 in the first quarter of 2020 and the second quarter of 2019, respectively. As of June 30, 2020, five of our drilling rigs were operating.

Revenue for the second quarter of 2020 decreased 20% from the first quarter of 2020 and decreased 32% from the second quarter of 2019. The decreases were primarily due to less drilling rigs operating.

Dayrates for the second quarter of 2020 averaged $18,340, a 6% decrease from the first quarter of 2020 and an 1% decrease from the second quarter of 2019. The decreases were both primarily due to less drilling rigs operating.

Operating costs for the second quarter of 2020 decreased 18% from the first quarter of 2020 and decreased 29% from the second quarter of 2019. The decreases were both primarily due to less drilling rigs operating.

We have three 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. During the second quarter of 2020, we recorded $9.2 million in early termination fees. We recorded $4.8 million in early termination fees in the first six months of 2019.

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

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

Mid-Stream

Second quarter 2020 liquids sold per day increased 21% over the first quarter of 2020 and decreased 10% from the second quarter of 2019. The increase over the first quarter of 2020 was due to higher plant recoveries while operating our processing facilities in ethane recovery mode resulting in more liquids available for sale, while the decrease from the second quarter of 2019 was due to lower purchased volumes from fewer well connects. For the second quarter of 2020, gas processed per day decreased 7% from the first quarter of 2020 and decreased 6% from the second quarter of 2019. The decreases were primarily due to lower volumes from fewer new well connects on our processing systems. For the second quarter of 2020, gas gathered per day increased 4% over the first quarter of 2020 and decreased 13% from the second quarter of 2019, respectively. The increase over the first quarter of 2020 was due to adding new infill wells on one of our gathering systems in the Appalachian region, while the decrease from the second quarter of 2019 was due to declining volumes from most of our major systems in both the Appalachian region and the mid-continent area.

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NGLs prices in the second quarter of 2020 decreased 20% from the prices received in the first quarter of 2020 and decreased 38% from the prices received in the second 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 second quarter of 2020 decreased 18% from the first quarter of 2020 and decreased 30% from the second quarter of 2019. The decreases were both primarily due to lower purchase prices, along with less purchased volumes.

At the Cashion processing facility in central Oklahoma, total throughput volume for the second quarter of 2020 averaged approximately 79.4 MMcf per day and total production of natural gas liquids averaged approximately 366,000 gallons per day. Through the first six months of 2020, we continued to connect new wells to this system for third party producers. Since the first of this year, we connected 11 new wells to this system from producers in the area. The recently acquired mid-continent production that we purchased at the end of 2019 is now being processed at our Reeding facility on our Cashion system beginning April 1, 2020. Also beginning April 1, 2020, we started delivering the Perkins facility production to the Cashion Reeding facility. With this operational change, we were able to shut down the Perkins processing plant resulting in overall operating cost savings. 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 second quarter of 2020 was 181.8 MMcf per day while the average gathered volume for June 2020 was approximately 169.3 MMcf per day as the new Bakerstown wells started to decline. During the second quarter of 2020, we added one new infill well to this system. This was the fourth and final well added to the Bakerstown pad.

At the Hemphill processing facility located in the Texas panhandle, average total throughput volume for the second quarter of 2020 was 52.4 MMcf per day and total production of NGLs increased to approximately 183,000 gallons per day due to returning to full ethane recovery in May. We did not connect any new wells to this system in the second quarter of 2020. At this time there are no active rigs in the area and we do not anticipate any new well connects for this system in 2020.

At the Segno gathering system located in East Texas, the average throughput volume for the second quarter of 2020 decreased to 42.4 MMcf per day due to declining production volume along with no new drilling activity in the area. During the second quarter of 2020, we did not connect any new wells to this system. We do not anticipate connecting any new wells to this system in 2020 but UPC will continue to perform some workovers in addition to some recompletions on existing wells connected to this system.

Anticipated 2020 capital expenditures for this segment will be approximately $10.8 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.

The significant risks and uncertainties related to the company’s liquidity has caused the company to conclude there continues to be substantial doubt about the company’s ability to continue as a going concern.

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


	Six Months Ended June 30,						% Change
	2020		2019
	(In thousands except percentages)
Net cash provided by operating activities	26,467		127,501		(79)	%
Net cash used in investing activities	(19,517)		(242,611)		92	%
Net cash provided by financing activities	29,473		109,327		(73)	%
Net increase (decrease) in cash and cash equivalents	$	36,423	$	(5,783)

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 six months of 2020 decreased by $101.0 million as compared to the first six 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

Cash flows used in investing activities decreased by $223.1 million for the first six months of 2020 compared to the first six months of 2019. The change was due primarily to a decrease in capital expenditures due to decreases in wells drilled and oil and gas property acquisitions partially offset by a decrease in the proceeds received from the disposition of assets. For additional information on capital expenditures, see below under Capital Requirements.

Cash Flows from Financing Activities

Cash flows provided by financing activities decreased by $79.9 million for the first six months of 2020 compared to the first six 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 June 30, 2020, we had unrestricted cash and cash equivalents totaling $37.0 million and had borrowed $124.0 million, $8.0 million, and $34.0 million of the amounts available under the Unit, DIP, and Superior credit agreements, respectively.

Below, we summarize certain financial information as of June 30, 2020 and 2019 and for the six months ended June 30, 2020 and 2019:


	June 30,						% Change ⁽²⁾
	2020		2019
	(In thousands except percentages)
Working capital	$	(104,738)	$	(64,125)	(63)	%
Current portion of long-term debt	$	124,000	$	—	NM
Debtor-in-possession financing	$	8,000	$	—	NM
Long-term debt ⁽¹⁾	$	34,000	$	756,590	(96)	%
Shareholders’ equity attributable to Unit Corporation	$	(128,176)	$	1,389,873	(109)	%
Net loss attributable to Unit Corporation	$	(986,143)	$	(12,013)	NM

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

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

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Working Capital

Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative activity. We had negative working capital of $104.7 million and $64.1 million as of June 30, 2020 and 2019, respectively. The decrease in working capital is primarily due to the springing maturity of the Unit credit agreement and the determination to treat the borrowings as current liabilities and a decrease in accounts receivable due to lower revenues partially offset by reduction in accounts payable and an increase in cash and cash equivalents and certain liabilities being classified as subject to compromise. The Superior credit agreement is used primarily for working capital and capital expenditures and the DIP credit facility is used to fund the operation of the Debtors and the Chapter 11 Cases. At June 30, 2020, we had borrowed $124.0 million and $34.0 million under the Unit and Superior credit agreements, respectively. As of June 30, 2020, we had borrowed $8.0 million under the DIP Credit Facility. The effect of our derivative contracts decreased working capital by $5.0 million as of June 30, 2020 and increased working capital by $8.5 million as of June 30, 2019.

This table summarizes certain operating information:


	Six Months Ended
	June 30,						% Change
	2020		2019
Oil and Natural Gas:
Oil production (MBbls)	1,220		1,414		(14)	%
NGLs production (MBbls)	1,827		2,417		(24)	%
Natural gas production (MMcf)	20,378		26,659		(24)	%
Equivalent barrels (MBoe)	6,444		8,274		(22)	%
Average oil price per barrel received	$	32.93	$	58.16	(43)	%
Average oil price per barrel received excluding derivatives	$	34.20	$	55.86	(39)	%
Average NGLs price per barrel received	$	3.67	$	14.11	(74)	%
Average NGLs price per barrel received excluding derivatives	$	3.67	$	14.11	(74)	%
Average natural gas price per Mcf received	$	1.16	$	2.18	(47)	%
Average natural gas price per Mcf received excluding derivatives	$	1.12	$	2.11	(47)	%



Contract Drilling:
Average number of our drilling rigs in use during the period	13.9		30.0		(54)	%
Total drilling rigs available for service at the end of the period	58		57		2	%
Average dayrate	$	19,165	$	18,412	4	%
Mid-Stream:
Gas gathered—Mcf/day	397,037		457,859		(13)	%
Gas processed—Mcf/day	160,943		163,725		(2)	%
Gas liquids sold—gallons/day	582,546		681,070		(14)	%
Number of natural gas gathering systems	18		21		(14)	%
Number of processing plants	11		12		(8)	%

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 six 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 $662,000 per month ($7.9 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 six months of 2020 was $1.16 compared to $2.18 for the first six months of 2019. Based on our first six months of 2020 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a

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$387,000 per month ($4.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of derivatives, would have a $560,000 per month ($6.7 million annualized) change in our pre-tax operating cash flow. In the first six months of 2020, our average oil price per barrel received, including the effect of derivatives, was $32.93 compared with an average oil price, including the effect of derivatives, of $58.16 in the first six months of 2019 and our first six months of 2020 average NGLs price per barrel received, including the effect of derivatives was $3.67 compared with an average NGLs price per barrel of $14.11 in the first six months of 2019.

Because commodity prices affect the value of our oil, NGLs, and natural gas reserves, declines in those prices can cause a decline in the carrying value of our oil and natural gas properties. Price declines can also hurt the semi-annual determination of the amount available for us to borrow under our Unit credit agreement since that determination is based mainly on the value of our oil, NGLs, and natural gas reserves. A reduction could limit our ability to carry out our planned capital projects. In the first quarter of 2020, the unamortized cost of our oil and gas properties exceeded the ceiling of our proved oil, NGLs, and natural gas reserves. As a result, we recorded a non-cash ceiling test write down of $267.8 million pre-tax ($220.8 million, net of tax). During the second quarter of 2020, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of $109.3 million pre-tax ($109.3 million, net of tax). At June 30, 2020, the 12-month average unescalated prices were $47.17 per barrel of oil, $18.07 per barrel of NGLs, and $2.07 per Mcf of natural gas, and then are adjusted for price differentials.

During the first quarter of 2020, in addition to the impairment evaluations of our proved and unproved oil and gas properties, we also evaluated the carrying value of our salt water disposal assets. As a result of our revised forecast of asset utilization, we determined certain assets were no longer expected to be utilized and wrote off certain salt water disposal assets that we 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.

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. We anticipate a non-cash ceiling test write-down in the third quarter of 2020 before re-emergence from bankruptcy in our predecessor company using 12-month average prices as of August 2020. We will be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, and those values may materially change relative to our historical consolidated financial statements.

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.

Contract Drilling Operations

Many factors influence the number of drilling rigs we are working 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 for oil and natural gas 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 six months of 2020, our average dayrate was $19,165 per day compared to $18,412 per day for the first six months of 2019. The average number of our drilling rigs used in the first six months of 2020 was 13.9 drilling rigs compared with 30.0 drilling rigs in the first six months of 2019. Based on the average utilization of our drilling rigs during the first six months of 2020, a $100 per day change in dayrates has a $1,390 per day ($0.5 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 $14.8 million for the first six months of 2019, from our contract drilling segment and eliminated the associated operating expense of $13.1 million during the first six months of 2019, yielding $1.7 million during the first six

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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 six months of 2020.

At March 31, 2020, due to market conditions, we performed impairment testing on two asset groups which were comprised of 44 SCR diesel-electric drilling rigs and 14 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 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 2,085 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 six months of 2020 and 2019, our mid-stream operations purchased $8.1 million and $24.8 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $2.2 million and $3.6 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.

This segment gathered an average of 397,037 Mcf per day in the first six months of 2020 compared to 457,859 Mcf per day in the first six months of 2019. It processed an average of 160,943 Mcf per day in the first six months of 2020 compared to 163,725 Mcf per day in the first six months of 2019. The NGLs sold was 582,546 gallons per day in the first six months of 2020 compared to 681,070 gallons per day in the first six months of 2019. Gas gathered volumes per day in the first six months of 2020 decreased 13% compared to the first six 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 a new acquisition. Gas processed volumes for the first six months of 2020 decreased 2% compared to the first six months of 2019 due to connecting fewer wells to our processing system along with declining volumes on most major systems, which was partially offset by added volumes from new well connects and from a new acquisition at our Cashion processing facility. NGLs sold in the first six months of 2020 decreased 14% compared to the first six months of 2019 due to declining volumes on several major processing systems and operating several of our processing facilities in ethane rejection mode.

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 Senior Subordinated Notes

Unit Credit Agreement. Due to the Credit Agreement Extension Condition and acceleration of debt obligations resulting from filing the Chapter 11 Cases, the company's debt associated with the Unit credit agreement is reflected as a current liability in its consolidated balance sheets as of June 30, 2020 and December 31, 2019. The classification as a current liability due to the Credit Agreement Extension Condition is 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. 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 Unit credit agreement were automatically stayed because of the Chapter 11 Cases.

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claims under the Unit credit facility or the DIP credit facility. As of June 30, 2020, we had $8.0 million outstanding under the DIP credit facility.

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 1.00%) 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 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, provide general working capital, and for letters of credit for Superior.

Superior's credit agreement is not guaranteed by Unit. Superior and its subsidiaries were not parties to the RSA and are 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	%

Subordinated Notes. As of June 30, 2020, we had an aggregate principal amount of $650.0 million outstanding on the Notes. Interest on the Notes was payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes were scheduled to mature on May 15, 2021. In issuing the Notes, we incurred fees of $14.7 million that are being amortized as debt issuance cost until maturity. In the second quarter, we wrote off the remaining debt issuance costs due to the filing of the Bankruptcy Petitions. The Notes plus accrued interest as of the Petition Date are included in liabilities subject to compromise in the condensed consolidated balance sheets as of June 30, 2020.

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Indenture), establishing the terms of and providing for issuing the Notes. On the Effective Date, by operation of the Plan, all outstanding obligations under the Notes were cancelled.

Unit, as the parent company, has no significant independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) were full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Superior was not a Guarantor of the Notes as of the Petition Date. Excluding Superior, any of our other subsidiaries that were not Guarantors were minor. There are no significant restrictions on our ability to receive funds from any subsidiary through dividends, loans, advances, or otherwise.

On the Effective Date, by operation of the Plan, the Debtors' outstanding obligations under the Notes and the 2011 Indenture were cancelled.

DIP Credit Agreement. As contemplated by the RSA, the Debtors entered into the DIP credit agreement under which the DIP Lenders agreed to provide the company with the $36.0 million new money multi-DIP credit facility. On June 19, 2020, the Bankruptcy Court granted final approval of the DIP credit facility. As of June 30, 2020, we had $8.0 million outstanding under the DIP credit agreement.

Prior to 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.

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), providing for a $140 million senior secured revolving credit facility (new RBL facility) and a $40 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 and its subsidiaries) (the Guarantors), (iii) the lenders party thereto from time to time and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent.

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On the Effective Date, the Borrowers had (i) $40 million in principal amount of Term Loans outstanding under the new term loan facility, (ii) $92 million in principal amount of Revolving Loans outstanding under the new RBL facility and (iii) approximately $6.68 million of outstanding letters of credit.

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 paying down debt. 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 six months of 2020 compared to 63 gross wells (17.41 net wells) drilled by Unit and other operators in which we participated in the first six months of 2019.

Capital expenditures for oil and gas properties on the full cost method for the first six months of 2020 by this segment, excluding $0.2 million for acquisitions and a $3.4 million reduction in the ARO liability, totaled $9.9 million. Capital expenditures for the first six months of 2019, excluding $3.3 million for acquisitions and an $3.7 million increase in the ARO liability, totaled $195.5 million.

For 2020, we do not currently have plans to drill wells pending our ability to refinance or restructure our debt.

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.

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 $2.8 million for capital expenditures during the first six months of 2020, compared to $24.9 million for capital expenditures during the first six months of 2019.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. At the Cashion processing facility in central Oklahoma, total throughput volume for the second quarter of 2020 averaged approximately 79.4 MMcf per day and total production of natural gas liquids averaged approximately 366,000 gallons per day. Through the first six months of 2020, we continued to connect new wells to this system for third party producers. Since the first of this year, we connected 11 new wells to this system from producers in the area. The recently acquired mid-continent production that we purchased at the end of 2019 is now being processed at our Reeding facility on our Cashion system beginning April 1, 2020. Also beginning April 1, 2020, we started delivering the Perkins facility production to the Cashion Reeding facility. With this operational change, we were able to shut down the Perkins processing plant resulting in overall operating cost savings. The total processing capacity on the Cashion system is 105 MMcf per day.

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During the first six months of 2020, our mid-stream segment incurred $9.0 million in capital expenditures as compared to $32.6 million in the first six months of 2019. For 2020, our estimated capital expenditures will be approximately $10.8 million.

Contractual Commitments

At June 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⁾	$	172,383	$	136,256	$	1,489	$	34,638	$	—
Operating leases ⁽²⁾	7,678		4,666		2,928		27		57
Finance lease interest and maintenance ⁽³⁾	1,552		1,535		17		—		—
Firm transportation commitments ⁽⁴⁾	1,581		996		585		—		—
Total contractual obligations	$	183,194	$	143,453	$	5,019	$	34,665	$	57

_______________________

1.See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Unit credit agreement and includes interest calculated using our June 30, 2020 interest rates of 2.3% for our Unit credit agreement, 7.5% for our DIP credit agreement, and 2.2% for our Superior credit agreement. At June 30, 2020, our Unit credit agreement is reflected as a current liability in our consolidated balance sheet because the filing of the Chapter 11 Cases constituted an event of default under our Unit credit agreement and the Notes and accelerated the Debtors' obligations under the Unit credit agreement and the Notes. The outstanding Unit credit agreement balance as of June 30, 2020 was $124.0 million. Our DIP credit agreement has an outstanding balance of $8.0 million as of June 30, 2020. Our Superior credit agreement has a maturity date of May 10, 2023 and an outstanding balance of $34.0 million as of June 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 2032. We also have short-term lease commitments of $0.3 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 October 2020. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.

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 $1.4 million and $0.1 million, respectively.

4.We have firm transportation commitments to transport our natural gas from various systems for approximately $1.0 million over the next twelve months and $0.6 million for the two years thereafter.

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At June 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⁾	$	6,006	Unknown		Unknown		Unknown		Unknown
Separation benefit plans ⁽²⁾	$	22,624	Unknown		Unknown		Unknown		Unknown
Asset retirement liability ⁽³⁾	$	64,248	$	1,104	$	2,988	$	3,568	$	56,588
Gas balancing liability ⁽⁴⁾	$	3,823	Unknown		Unknown		Unknown		Unknown
Workers’ compensation liability ⁽⁵⁾	$	12,112	$	4,511	$	1,262	$	832	$	5,507
Finance lease obligations⁽⁶⁾	$	5,319	$	5,157	$	162	$	—	$	—
Contract liability ⁽⁷⁾	$	5,625	$	2,856	$	2,736	$	12	$	21
Other long-term liabilities⁽⁸⁾	$	1,217	$	—	$	1,217	$	—	$	—

_______________________

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.

2.Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Currently there are no participants in the Senior Plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (“Special Plan”). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. As of June 30, 2020, this is included in liabilities subject to compromise in our Unaudited Condensed Consolidated Balance Sheets.

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 June 30, 2020, based on our second quarter 2020 average daily production, the approximated percentages of our production under derivative contracts are as follows:


	2020
Daily oil production	30	%
Daily natural gas production	29	%

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 June 30, 2020 evaluation, we believe the risk of non-performance by our counterparties is not material. At June 30, 2020, the fair values of the net assets we had with each of the counterparties to our commodity derivative transactions are as follows:


	June 30, 2020
	(In thousands)
Bank of Oklahoma	$	(4,391)
Bank of America	(600)
Bank of Montreal	(165)
Total net liabilities	$	(5,156)

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 June 30, 2020, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative liabilities of $5.0 million and non-current derivative liabilities of $0.1 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 June 30 are as follows:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
	(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of ($1,243), $2,658, ($691), and $5,314, respectively	$	(6,937)	$	7,927	$	(6,454)	$	995
	$	(6,937)	$	7,927	$	(6,454)	$	995

Stock and Incentive Compensation

During the first six months of 2020, we granted no shares of restricted stock. We recognized compensation expense of $4.1 million for all of our restricted stock. We did not capitalize any compensation cost to oil and natural gas properties since we are currently not drilling.

During the first six 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 six months of 2019, we recognized $3.4 million in compensation expense and capitalized $0.6 million for these awards. During the first six months of 2019, we recognized compensation expense of $8.5 million for all of our restricted stock and stock options and capitalized $1.3 million of compensation cost to oil and natural gas properties.

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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

Adopted Standards

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 is 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 June 30, 2020 versus Quarter Ended June 30, 2019

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


	Quarter Ended June 30,								Percent Change ⁽¹⁾
	2020			2019
	(In thousands unless otherwise specified)
Total revenue	$	89,007		$	165,146		(46)	%
Net loss	$	(215,565)		$	(8,017)		NM
Net income attributable to non-controlling interest	$	84		$	492		(83)	%
Net loss attributable to Unit Corporation	$	(215,649)		$	(8,509)		NM

Oil and Natural Gas:
Revenue	$	26,956		$	77,815		(65)	%
Operating costs excluding depreciation, depletion, and amortization	$	71,540		$	36,242		97	%
Depreciation, depletion, and amortization	$	22,059		$	38,751		(43)	%
Impairment of oil and natural gas properties	$	109,318		$	—		—	%
Average oil price (Bbl)	$	20.96		$	59.94		(65)	%
Average NGLs price (Bbl)	$	4.11		$	12.52		(67)	%
Average natural gas price (Mcf)	$	1.08		$	1.86		(42)	%
Oil production (MBbls)	546			726			(25)	%
NGL production (MBbls)	862			1,210			(29)	%
Natural gas production (MMcf)	9,576			13,288			(28)	%
Depreciation, depletion, and amortization rate (Boe)	$	6.96		$	8.94		(22)	%

Contract Drilling:
Revenue	$	29,202		$	43,037		(32)	%
Operating costs excluding depreciation	$	20,951		29,308			(29)	%
Depreciation	$	2,946		$	13,504		(78)	%


Percentage of revenue from daywork contracts	100		%	100		%	—	%
Average number of drilling rigs in use	9.1			28.6			(68)	%
Average dayrate on daywork contracts	$	18,340		$	18,491		(1)	%

Mid-Stream:
Revenue	$	32,849		$	44,294		(26)	%
Operating costs excluding depreciation and amortization	$	22,612		$	32,491		(30)	%
Depreciation and amortization	$	10,348		$	12,102		(14)	%

Gas gathered--Mcf/day	404,831			465,714			(13)	%
Gas processed--Mcf/day	155,555			165,682			(6)	%
Gas liquids sold--gallons/day	637,420			711,192			(10)	%

Corporate and Other:
General and administrative expense	$	25,814		$	10,064		156	%
Other depreciation	$	607		$	1,935		(69)	%
Gain (loss) on disposition of assets	$	(877)		$	422		NM
Other income (expense):
Interest income	$	58		$	3		NM
Interest expense, net	$	(7,666)		$	(8,998)		(15)	%
Write-off of debt issuance costs	$	(2,426)		$	—		—	%
Gain (loss) on derivatives	$	(6,937)		$	7,927		(188)	%
Other	$	43		$	6		NM
Income tax benefit	$	(6,455)		$	(1,874)		NM
Average interest rate	6.1		%	6.5		%	(6)	%
Average long-term debt outstanding	$	410,593		$	731,037		(44)	%

_________________________

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

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Oil and Natural Gas

Oil and natural gas revenues decreased $50.9 million or 65% in the second quarter of 2020 as compared to the second quarter of 2019 primarily due to lower commodity prices and volumes. In the second quarter of 2020, as compared to the second quarter of 2019, oil production decreased 25%, natural gas production decreased 28%, and NGLs production decreased 29%. Including derivatives settled, average oil prices decreased 65% to $20.96 per barrel, average natural gas prices decreased 42% to $1.08 per Mcf, and NGLs prices decreased 67% to $4.11 per barrel.

Oil and natural gas operating costs increased $35.3 million or 97% between the comparative second quarters of 2020 and 2019 primarily due to a $45.0 million estimated litigation settlement and a $6.1 additional separation benefit expense due to a reduction in our workforce partially offset by lower lease operating expenses (LOE) and gross production taxes.

Depreciation, depletion, and amortization (DD&A) decreased $16.7 million or 43% due primarily to a 22% decrease in the DD&A rate and a 28% decrease in equivalent production. The decrease in our DD&A rate in the second quarter of 2020 compared to the second quarter of 2019 resulted primarily from reduced net book value due to ceiling test write-down.

During the second quarter of 2020, we recorded a non-cash ceiling test write-down of 109.3 million pre-tax ($109.3 million, net of tax). We did not have a ceiling test write-down in the second quarter of 2019.

Contract Drilling

Drilling revenues decreased $13.8 million or 32% in the second quarter of 2020 versus the second quarter of 2019. The decrease was due primarily to a 68% decrease in the average number of drilling rigs in use and a 1% decrease in the average dayrate. Average drilling rig utilization decreased from 28.6 drilling rigs in the second quarter of 2019 to 9.1 drilling rigs in the second quarter of 2020.

Drilling operating costs decreased $8.4 million or 29% between the comparative second quarters of 2020 and 2019. The decrease was due primarily to less drilling rigs operating partially offset by a recorded expense for $5.3 million for separation benefit expense due to a reduction in our workforce. Contract drilling depreciation decreased $10.6 million or 78% in the second quarter of 2020 versus the second quarter of 2019 also due to less drilling rigs operating and from the lower depreciable net book value due to impairments in the first quarter of 2020.

Mid-Stream

Our mid-stream revenues decreased $11.4 million or 26% in the second quarter of 2020 as compared to the second quarter of 2019 due primarily to lower gas, NGLs, and condensate prices and decreased NGL, condensate and purchased volumes. Gas processed volumes per day decreased 6% between the comparative quarters primarily due to connecting fewer new wells and declining volumes on most of our major processing systems, offset partially by added volumes from a new acquisition to our Cashion gathering system. Gas gathered volumes per day decreased 13% between the comparative quarters due to declining volumes from most of our major systems offset by higher volume on our Cashion system.

Operating costs decreased $9.9 million or 30% in the second quarter of 2020 compared to the second quarter of 2019 primarily due to lower purchase prices along with reduced purchase volumes. Depreciation and amortization decreased $1.8 million, or 14%, primarily due to impairing the carrying value of several of our systems in the first quarter of 2020.

General and Administrative

Corporate general and administrative expenses increased $15.8 million or 156% in the second quarter of 2020 as compared to the second quarter of 2019 primarily due to higher consulting and outside legal fees. We incurred $16.5 million in advisory and restructuring fees in the second quarter of 2020. Also during the second quarter of 2020, we had a reduction to our workforce and incurred additional separation benefit expense of $4.0 million.

Gain (Loss) on Disposition of Assets

There was a $0.9 million loss on disposition of assets in the second quarter of 2020 primarily related to the sale of the corporate jet and some drilling equipment and vehicles. For the second quarter of 2019, we had a gain of $0.4 million which was primarily related to assets held for sale that were sold which consisted of miscellaneous drilling rig components.

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Other Income (Expense)

Interest expense, net of capitalized interest, decreased $1.3 million between the comparative second quarters of 2020 and 2019 due primarily to a lower average interest rate partially offset by a 44% decrease in average long-term debt outstanding and no capitalized interest in the second quarter of 2020. 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 second quarter of 2020 compared to $4.2 million for the second quarter of 2019 which was netted against our gross interest of $7.7 million and $13.2 million for the second quarters of 2020 and 2019, respectively. Our average interest rate decreased from 6.5% in the second quarter of 2019 to 6.1% in the second quarter of 2020 and our average debt outstanding decreased $320.4 million in the second quarter of 2020 compared to the second quarter of 2019 primarily due to the Notes now being classified as liabilities subject to compromise in our Unaudited Condensed Consolidated Balance Sheets.

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 $14.9 million 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 a benefit of $6.5 million in the second quarter of 2020 compared to $1.9 million in the second quarter of 2019 primarily due to decreased pre-tax income. Our effective tax rate was 2.91% for the second quarter of 2020 compared to 18.95% for the second quarter of 2019. The rate change was primarily due to our income tax benefit for the second quarter of 2020 being offset by a valuation allowance. We did not have a current income tax benefit for the second quarter of 2020 or 2019. We paid no income taxes in the second quarter of 2020.

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Six Months Ended June 30, 2020 versus Six Months Ended June 30, 2019

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


	Six Months Ended June 30,								Percent Change ⁽¹⁾
	2020			2019
	(In thousands unless otherwise specified)
Total revenue	$	211,383		$	354,837		(40)	%
Net loss	$	(1,019,239)		$	(10,299)		NM
Net income (loss) attributable to non-controlling interest	$	(33,096)		$	1,714		NM
Net loss attributable to Unit Corporation	$	(986,143)		$	(12,013)		NM

Oil and Natural Gas:
Revenue	$	75,478		$	163,910		(54)	%
Operating costs excluding depreciation, depletion, and amortization	$	102,203		$	68,956		48	%
Depreciation, depletion, and amortization	$	58,787		$	74,518		(21)	%
Impairment of oil and natural gas properties	$	377,154		$	—		—	%
Average oil price (Bbl)	$	32.93		$	58.16		(43)	%
Average NGLs price (Bbl)	$	3.67		$	14.11		(74)	%
Average natural gas price (Mcf)	$	1.16		$	2.18		(47)	%
Oil production (MBbls)	1,220			1,414			(14)	%
NGL production (MBbls)	1,827			2,417			(24)	%
Natural gas production (MMcf)	20,378			26,659			(24)	%
Depreciation, depletion, and amortization rate (Boe)	$	8.70		$	8.64		1	%

Contract Drilling:
Revenue	$	65,834		$	94,192		(30)	%
Operating costs excluding depreciation	$	46,400		60,709			(24)	%
Depreciation	$	14,691		$	26,203		(44)	%

Impairment of contract drilling equipment	$	410,126		$	—		—	%
Percentage of revenue from daywork contracts	100		%	100		%	—	%
Average number of drilling rigs in use	13.9			30.0			(54)	%
Average dayrate on daywork contracts	$	19,165		$	18,412		4	%

Mid-Stream:
Revenue	$	70,071		$	96,735		(28)	%
Operating costs excluding depreciation and amortization	$	50,223		$	71,846		(30)	%
Depreciation and amortization	$	22,621		$	23,828		(5)	%
Impairment	$	63,962		$	—		—	%
Gas gathered--Mcf/day	397,037			457,859			(13)	%
Gas processed--Mcf/day	160,943			163,725			(2)	%
Gas liquids sold--gallons/day	582,546			681,070			(14)	%

Corporate and Other:
Loss on abandonment of assets	$	(17,554)		$	—		—	%
General and administrative expense	$	37,367		$	19,805		89	%
Other depreciation	$	1,478		$	3,869		(62)	%
Loss on disposition of assets	$	(1,267)		$	(1,193)		6.2	%
Other income (expense):
Interest income	$	58		$	44		32	%
Interest expense, net	$	(20,923)		$	(17,577)		19	%
Write-off of debt issuance costs	$	(2,426)		$	—		—	%
Gain (loss) on derivatives	$	(6,454)		$	995		NM
Other	$	103		$	11		NM
Income tax benefit	$	(9,880)		$	(2,318)		NM
Average interest rate	6.2		%	6.5		%	(5)	%
Average long-term debt outstanding	$	586,048		$	710,494		(18)	%

_________________________

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

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Oil and Natural Gas

Oil and natural gas revenues decreased $88.4 million or 54% in the first six months of 2020 as compared to the first six months of 2019 primarily due to lower commodity prices and volumes. In the first six months of 2020, as compared to the first six months of 2019, oil production decreased 14%, natural gas production decreased 24%, and NGLs production decreased 24%. Including derivatives settled, average oil prices decreased 43% to $32.93 per barrel, average natural gas prices decreased 47% to $1.16 per Mcf, and NGLs prices decreased 74% to $3.67 per barrel.

Oil and natural gas operating costs increased $33.2 million or 48% between the comparative first six months of 2020 and 2019 primarily due to a $45.0 million estimated litigation settlement, a $6.1 additional separation benefit expense due to a reduction in our workforce, and decreased G&G expenses capitalized partially offset by lower LOE and gross production taxes.

DD&A decreased $15.7 million or 21% due primarily to a 1% increase in the DD&A rate and a 22% decrease in equivalent production.

During the first six months of 2020, we recorded non-cash ceiling test write-downs of $377.2 million pre-tax ($330.1 million, net of tax). We did not have a ceiling test write-down in the first six months of 2019. We recorded expense of $17.6 million related to the write down of our salt water disposal asset that we consider abandoned in first six months of 2020.

Contract Drilling

Drilling revenues decreased $28.4 million or 30% in the first six months of 2020 versus the first six months of 2019. The decrease was due primarily to a 54% decrease in the average number of drilling rigs in use partially offset by a 4% increase in the average dayrate. Average drilling rig utilization decreased from 30.0 drilling rigs in the first six months of 2019 to 13.9 drilling rigs in the first six months of 2020.

Drilling operating costs decreased $14.3 million or 24% between the comparative first six months of 2020 and 2019. The decrease was due primarily to less drilling rigs operating partially offset by a recorded expense for $5.3 million for separation benefit expense due to a reduction in our workforce. Contract drilling depreciation decreased $11.5 million or 44% in the first six months of 2020 versus the first six months of 2019 also due to less drilling rigs operating and from lower depreciable net book value due to impairments recognized in the first quarter 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 $26.7 million or 28% in the first six months of 2020 as compared to the first six months of 2019 due primarily to lower gas, NGLs, and condensate prices and decreased liquids, condensate volumes, and gas sales. Gas processed volumes per day decreased 2% between the comparative periods primarily due to connecting fewer new wells to our processing systems. Gas gathered volumes per day decreased 13% between the comparative periods due to declining volumes from most of our major systems offset by higher volume on our Cashion system.

Operating costs decreased $21.6 million or 30% in the first six months of 2020 compared to the first six months of 2019 primarily due to lower purchase prices along with lower purchased volumes. Depreciation and amortization decreased $1.2 million, or 5%, 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.

General and Administrative

Corporate general and administrative expenses increased $17.6 million or 89% in the first six months of 2020 as compared to the first six months of 2019 primarily due to higher consulting and outside legal fees. We incurred $20.2 million in advisory and restructuring fees in the first half of 2020. Also during the second quarter of 2020, we had a reduction to our workforce and incurred additional separation benefit expense of $4.0 million.

Loss on Disposition of Assets

There was a $1.3 million loss on disposition of assets in the first six months of 2020 primarily related to due to the sale of the corporate jet, vehicles, and drill pipe and other drilling equipment. For the first six months of 2019, we had a loss of $1.2 million. Of this amount, $0.2 million was related to assets held for sale that were sold which consisted of three drilling rigs and other drilling components. The other $1.0 million was related to the sales of other drilling rig components and vehicles.

Other Income (Expense)

Interest expense, net of capitalized interest, increased $3.3 million between the comparative first six months of 2020 and 2019 due primarily to an 18% decrease in average long-term debt outstanding and no capitalized interest in the first six months of 2020 partially offset 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 six months of 2020 compared to $8.4 million for the first six months of 2019 and capitalized interest was netted against our gross interest of $20.9 million and $26.0 million for the first six months of 2020 and 2019, respectively. Our average interest rate decreased from 6.5% in the first six months of 2019 to 6.2% in the first six months of 2020 and our average debt outstanding decreased $124.4 million in the first six months of 2020 compared to the first six months of 2019 primarily due to the Notes now being classified as liabilities subject to compromise in our Unaudited Condensed Consolidated Balance Sheets.

Write-off of Debt Issuance Costs

Gain (Loss) on Derivatives

Gain (loss) on derivatives decreased by $7.4 million 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 a benefit of $9.9 million in the first six months of a benefit of 2020 compared to $2.3 million in the first six months of 2019 primarily due to decreased pre-tax income. Our effective tax rate was 0.96% for the first six months of 2020 compared to 18.4% for the first six months of 2019. The rate change was primarily due to our income tax benefit for the second quarter of 2020 being offset by a valuation allowance. We did not have a current income tax benefit for the first six months of 2019. We paid no income taxes in the first six months of 2020.

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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 six 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 $662,000 per month ($7.9 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 $387,000 per month ($4.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of hedging, would have a $560,000 per month ($6.7 million annualized) change in our pre-tax operating cash flow.

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

At June 30, 2020, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price

Contracted Market

Jul'20 - Dec'20

Natural gas - basis swap

30,000 MMBtu/day

$(0.275)

NGPL TEXOK

Jul'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

Jul'20 - Dec'20

Natural gas - three-way collar

30,000 MMBtu/day

$2.50 - $2.20 - $2.80

IF - NYMEX (HH)

Jul'20 - Sep'20

Crude oil - collar

112,000 Bbl/month

$20.00 - $26.50

WTI - NYMEX

After June 30, 2020, these derivatives were entered into:

Term

Commodity

Contracted Volume

Weighted Average Fixed Price

Contracted Market

Sep'20 - Dec'20

Natural gas - swap

10,000 MMBtu/day

$2.72

IF - NYMEX (HH)

Sep'20 - Oct'21

Natural gas - swap

20,000 MMBtu/day

$2.77

IF - NYMEX (HH)

Jan'21 - Oct'21

Natural gas - swap

30,000 MMBtu/day

$2.85

IF - NYMEX (HH)

Nov'21 - Dec'21

Natural gas - swap

45,000 MMBtu/day

$2.90

IF - NYMEX (HH)

Jan'22 - Dec'22

Natural gas - 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

After June 30, 2020, we converted the natural gas three-way collars into two-way collars by repurchasing the sold puts ($2.20 strike prices) and paying the current fair value for those puts.

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreements and the Notes. At June 30, 2020, we had indebtedness of $124.0 million under the Unit credit agreement, $34.0 million under the Superior credit agreement, and $8.0 million under the DIP credit agreement, all of which bore interest at floating rates. At our election, borrowings under the Unit credit agreement and the Superior credit agreement may be fixed at the LIBOR Rate for periods of up to 180 days. Based on our average outstanding long-term debt subject to a variable rate in the first six months of 2020, a 1% increase in the floating rate would reduce our annual pre-tax cash flow by approximately $1.3 million. Under our Notes, we pay a fixed rate of interest of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year). On May 15, 2020, the company elected not to make the approximate $21.5 million semi-annual interest payment due on the Notes. On the Effective Date, by operation of the Plan, the Debtors' outstanding obligations under the Notes and the 2011 Indenture were cancelled. For further information, see Note 8 – Long-Term Debt and Other Long-Term Liabilities—Long-Term Debt—6.625% Senior Subordinated Notes.

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Item 4. Controls and Procedures

Our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the 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 also is based in part on certain assumptions about the likelihood of future events, and there is no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to an error or fraud may occur and not be detected. We monitor our Disclosure Controls and 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 June 30, 2020 due to a material weakness in ICFR as 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.

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

Plan for Remediation of the Material Weakness. We intend to take steps we believe address the underlying cause of the material weakness, including a redesign of certain management review controls related to complex accounting matters, the establishment of documentation standards, provide 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 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 June 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). The Debtors emerged from the Chapter 11 Cases on the Effective Date. For further information, please see Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern—Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code.

UPC is named in three purported class action lawsuits that are stayed as a result of the Chapter 11 Cases: (i) Panola Independent School District No. 4, et al. v. Unit Petroleum Company, No. CJ-07-215, District Court of Latimer County, Oklahoma, (ii) Cockerell Oil Properties, Ltd. v. Unit Petroleum Company, No. 16-cv-135-JHP, United States District Court for the Eastern District of Oklahoma, and (iii) Chieftain Royalty Company v. Unit Petroleum Company, No. CJ-16-230, District Court of LeFlore County, Oklahoma. For further information, please see Part II – “Item 1. Legal Proceedings” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. On August 21, 2020, the Debtors agreed, subject to Bankruptcy Court approval, to settle the Cockerell lawsuit for an allowed claim amount of $15.75 million and to settle the Chieftain lawsuit for an allowed claim amount of $29.25 million. Other than as agreed to in these settlements, the claims asserted by the plaintiffs in these lawsuits are disputed by the Debtors. Under the Plan and Confirmation Order, the Debtors established an equity pool at emergence from the Chapter 11 Cases, which consists of shares of New Common Stock that can be used to satisfy claims against UPC that are disputed but ultimately become allowed. Holders of such disputed claims ultimately determined to be allowed will receive shares of New Common Stock from the equity pool in accordance with the Plan. As disputed claims, such as these lawsuits, are allowed, disallowed or otherwise resolved, adjustments will be made to the equity pool correspondingly.

Item 1A. Risk Factors

In addition to the other information set forth in this quarterly report, you should carefully consider the factors discussed below, and in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019 and Part II, “Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, which could materially affect our business, financial condition or future results. The risks described in our Form 10-K for the year ended December 31, 2019 and Form 10-Q for the quarter ended March 31, 2020 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 Part I, Item 1A in our Form 10-K for the year ended December 31, 2019 and Part II, Item 1A in our Form 10-Q for the quarter ended March 31, 2020.

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 Cases could adversely affect our business and relationships with our customers, vendors, royalty or working interest owners, contractors, employees or suppliers. Due to these uncertainties, many risks exist, including the following:

•key suppliers or vendors could terminate their relationship with us or require additional financial assurances or enhanced performance from us;

•the ability to renew existing contracts and compete for new business may be adversely affected;

•the ability to attract, motivate and/or retain key executives and employees may be adversely affected;

•employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and

•competitors may take business away from us.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

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Restrictive covenants in our exit facility may restrict our ability to pursue our business strategies.

The exit facility limits our ability, among other things, to:

•incur additional indebtedness;

•incur liens;

•enter into sale and lease back transactions;

•make certain investments;

•make certain capital expenditures;

•consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;

•pay dividends or make other distributions or repurchase or redeem our stock;

•enter into transactions with our affiliates;

•engage or enter into any new lines of business;

•enter into certain marketing activities for hydrocarbons;

•create additional subsidiaries;

•prepay, redeem or repurchase certain of our indebtedness; and

•amend or modify certain provisions of our organizational documents.

The exit facility also requires us to comply with certain financial maintenance covenants as discussed above.

A breach of any of these restrictive covenants could result in a default under our exit facility. If a default occurs, the lenders under the exit facility may elect to declare all borrowings thereunder outstanding, together with accrued interest and other fees, to be immediately due and payable. The lenders under the exit facility would also have the right in these circumstances to terminate any commitments they have to provide further borrowings. 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. If such indebtedness were to be accelerated, our assets may not be sufficient to repay in full our secured indebtedness.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from the Chapter 11 Cases.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from the Chapter 11 Cases, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

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 debts were reduced through the Plan, 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.

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As a result of the Chapter 11 Cases, our historical financial information is not indicative of our future performance, which may be volatile.

As a result of the Chapter 11 Cases, the amounts reported in subsequent consolidated financial statements may materially change relative to our historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to the Plan. We are required to adopt the fresh start accounting rules, which means our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets and our financial results after the application of fresh start accounting may be different from historical trends.

On the Effective Date of the Plan, the composition of our board of directors changed substantially.

Under the Plan, our new board of directors changed substantially on the Effective Date and now consists of seven members, including Robert Anderson, Alan Carr, Phil Frohlich, Steven B. Hildebrand (the only remaining member of our prior board), David T. Merrill (who also serves as reorganized Unit’s Chief Executive Officer), Philip Smith and Andrei Verona. Our new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the board of directors and, thus, may have different views on the issues that will determine our future. As a result, our future strategy and plans may differ materially from those of the past.

Adverse publicity in connection with the Chapter 11 Cases or otherwise could negatively affect our business.

Adverse publicity or news coverage relating to us, including, but not limited to, publicity or news coverage in connection with the Chapter 11 Cases, may negatively impact our efforts to establish and promote name recognition and a positive image after emergence from the Chapter 11 Cases.

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 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.

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. 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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Holders of the New Common Stock and Warrants could be subject to U.S. federal withholding tax and/or U.S. federal income tax and corresponding tax reporting obligations upon the sale, exchange or other disposition of the New Common Stock and Warrants, which could adversely impact the trading and liquidity of the New Common Stock and Warrants.

The company believes that it is, and will remain for the foreseeable future, a “U.S. real property holding corporation” for U.S. federal income tax purposes. As a result, under the Foreign Investment in Real Property Tax Act (FIRPTA), non-U.S. holders may be subject to U.S. federal income tax on gain from the sale, exchange or other disposition of shares of New Common Stock and Warrants, in which case they would also be required to file U.S. federal income tax returns with respect to such gain, and may be subject to a U.S. federal withholding tax with respect to a disposition of shares of New Common Stock and Warrants. In general, whether these FIRPTA provisions apply depends on the amount of New Common Stock or Warrants that such non-U.S. holders hold and whether, at the time they dispose of their New Common Stock or Warrants, the New Common Stock is treated as regularly traded on an established securities market within the meaning of the applicable Treasury Regulations (regularly traded).

If the New Common Stock is regularly traded during a calendar quarter, (A) no withholding requirements would be imposed under FIRPTA on transfers of New Common Stock or Warrants and (B) only a non-U.S. holder who has held, actually or constructively, (i) more than 5% of New Common Stock or (ii) Warrants with a fair market value greater than 5% of the New Common Stock into which it is convertible, in each case at any time during the shorter of (x) the five-year period ending on the date of disposition, and (y) the non-U.S. holder’s holding period for its shares of New Common Stock or Warrants, would be subject to U.S. federal income tax on the sale, exchange or disposition of such shares of New Common Stock or Warrants during such calendar quarter under FIRPTA.

However, if during any calendar quarter the New Common Stock is not regularly traded, any purchaser of New Common Stock or Warrants generally will be required to withhold (and remit to the Internal Revenue Service (IRS)) 15% of the gross proceeds from the sale of the New Common Stock or Warrants unless provided with a certificate of non-foreign status or an IRS withholding certificate from the applicable seller. Because the New Common Stock and Warrants are being issued in book entry form through DTC, sellers may be unable to provide the necessary documentation to the purchasers to establish an exemption from withholding. Additionally, the purchasers may be unable to withhold from the purchase price and remit the withheld amount to the IRS if they cannot obtain the identifying information of the sellers. Accordingly, it may be difficult or impossible to complete a transfer in compliance with tax laws in any calendar quarter when the New Common Stock is not regularly traded.

The company is taking steps to have the New Common Stock quoted on one of the OTC markets and, if successful, the New Common Stock may be treated as regularly traded during any calendar quarter in which it is regularly quoted one of such OTC markets by brokers or dealers making a market in the New Common Stock. However, no assurances can be given that the reorganized Unit will complete such steps required to be regularly quoted on an OTC market or that the brokers or dealers will continue to regularly quote the New Common Stock on such OTC market. If the New Common Stock is not regularly traded, the trading and liquidity of the New Common Stock and Warrants could be adversely impacted as a result of the withholding and other tax obligations under FIRPTA. The company expects to complete the process during the fourth quarter of 2020 and will publicly disclose the results once completed.

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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 three months ended June 30, 2020:


Period	(a) Total Number of Shares Purchased	(b) Average Price Paid Per Share		(c) Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
April 1, 2020 to April 30, 2020	174	$	0.34	174	—
May 1, 2020 to May 31, 2020	—	—		—	—
June 1, 2020 to June 30, 2020	—	—		—	—
Total	174	$	0.34	174	—

Item 3. Defaults Upon Senior Securities

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 Unit credit agreement were automatically stayed because of the Chapter 11 Cases. For further information, see Note 8 – Long-Term Debt and Other Long-Term Liabilities—Long-Term Debt—Unit Credit Agreement.

The company elected not to make the approximate $21.5 million semi-annual interest payment due on the Notes on May 15, 2020. The company was entitled to a 30-day grace period after the interest payment date before an event of default would occur because of such non-payment. Filing of the Bankruptcy Petitions on May 22, 2020 constituted an event of default that accelerated the company’s obligations under the Notes. However, under the Bankruptcy Code, holders of the Notes were stayed from taking any action against the company or the other Debtors because of the default. For further information, see Note 8 – Long-Term Debt and Other Long-Term Liabilities—Long-Term Debt—6.625% Senior Subordinated Notes.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

Exhibits:


3.1			Amended and Restated Certificate of Incorporation of Unit Corporation, dated as of September 3, 2020 (filed as Exhibit 3.1 to Unit's Form 8-K dated September 10, 2020, which is incorporated herein by reference).

3.2			Amended and Restated Bylaws of Unit Corporation, dated as of September 3, 2020 (filed as Exhibit 3.2 to Unit's Form 8-K dated September 10, 2020, which is incorporated herein by reference).

10.1			Second Amended and Restated Limited Liability Company Agreement of Superior Pipeline Company, L.L.C., dated as of July 1, 2019.

10.2			Amendment No. 1 to the Second Amended and Restated Limited Liability Company Agreement of Superior Pipeline Company, L.L.C., dated as of July 1, 2019.

10.3			Restructuring Support Agreement, dated as of May 22, 2020, by and among Unit Corporation, Unit Petroleum Company, Unit Drilling Company, 8200 Unit Drive, L.L.C., Unit Drilling USA Colombia, L.L.C., Unit Drilling USA Colombia, L.L.C., the Consenting RBL Lenders party thereto, BOKF, NA Bank of Oklahoma as RBL Agent, and the Consenting Noteholders party thereto (filed as Exhibit 10.1 to Unit’s Form 8-K dated May 26, 2020, which is incorporated herein by reference).

10.4			Superpriority Senior Secured Debtor-in-Possession Credit Agreement, dated as of May 27, 2020, by and among Unit Corporation, Unit Petroleum Company, Unit Drilling Company, 8200 Unit Drive, L.L.C., Unit Drilling USA Colombia, L.L.C., Unit Drilling Colombia L.L.C., the lenders party thereto and BOKF, NA dba Bank of Oklahoma as Administrative Agent (filed as Exhibit 10.1 to Unit’s Form 8-K dated June 1, 2020, which is incorporated herein by reference)

10.5			Continuation Agreement, dated as of May 22, 2020, by and among Superior Pipeline Company, L.L.C., Unit Corporation, SPC Midstream Operating, L.L.C., SP Investor Holdings, LLC, 8200 Unit Drive, L.L.C., Unit Drilling Colombia, L.L.C., Unit Drilling Company, Unit Drilling USA Colombia, L.L.C. and Unit Petroleum Company (filed as Exhibit 10.1 to Unit’s Form 8-K dated May 26, 2020, which is incorporated herein by reference).

10.6			Amended and Restated Credit Agreement, dated as of September 3, 2020, among Unit Corporation, Unit Drilling Company, Unit Petroleum Company, the lenders party thereto from time to time, the guarantors party thereto and BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (filed as Exhibit 10.1 to Unit’s Form 8-K dated September 10, 2020, which is incorporated herein by reference).

10.7			Warrant Agreement, dated as of September 3, 2020, by and between Unit Corporation and American Stock Transfer & Trust Company, LLC (filed as Exhibit 10.2 to Unit’s Form 8-K dated September 10, 2020, which is incorporated herein by reference).

10.8			Registration Rights Agreement, dated as of September 9, 2020, by and between Unit Corporation and the holders party thereto (filed as Exhibit 10.3 to Unit’s Form 8-K dated September 10, 2020, which is incorporated herein by reference).

10.9			Unit Corporation Long Term Incentive Plan (filed as Exhibit 10.1 to Unit’s Form 8-K dated September 10, 2020, which is incorporated herein by reference).

10.10			Employment Agreement, dated as of September 3, 2020, by and between Unit Corporation and David Merrill (filed as Exhibit 10.2 to Unit’s Form 8-K dated September 10, 2020, which is incorporated herein by reference).

10.11			Employment Agreement, dated as of September 3, 2020, by and between Unit Corporation and Mark Schell (filed as Exhibit 10.3 to Unit’s Form 8-K dated September 10, 2020, which is incorporated herein by reference).

10.12			Amended and Restated Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (filed as Exhibit 10.4 to Unit’s Form 8-K dated September 10, 2020, which is incorporated herein by reference).

10.13			Amended and Restated Special Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (filed as Exhibit 10.5 to Unit’s Form 8-K dated September 10, 2020, which is incorporated herein by reference).

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10.14			Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (filed as Exhibit 10.6 to Unit’s Form 8-K dated September 10, 2020, which is incorporated herein by reference).

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:	October 21, 2020	By: /s/ David T. Merrill
		DAVID T. MERRILL
		President and Chief Executive Officer

Date:	October 21, 2020	By: /s/ Les Austin
		LES AUSTIN
		Senior Vice President and Chief Financial Officer