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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[x]☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 20172020
OR
[ ]☐ 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]
unt-20200630_g1.jpg
UNIT CORPORATION
(Exact name of registrant as specified in its charter)
Delaware73-1283193
(State or other jurisdiction of incorporation)(I.R.S. Employer Identification No.)
8200 South Unit Drive, Tulsa, OklahomaTulsa,Oklahoma74132
(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 classTrading Symbol(s)Name of each exchange on which registered
N/AN/AN/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 [x]☐            No [  ]☒ 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).
Yes [x]☒            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 [ x ]☒                Non-accelerated filer (Do not check if a smaller reporting company) [  ]☐
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 ☒  
Yes [  ]            No [x]  
As of October 20, 2017, 52,879,660The registrant had 54,504,879 shares of the issuer's common stock were outstanding.outstanding prior to the registrant's emergence from bankruptcy on September 3, 2020.


Table of Contents
TABLE OF CONTENTS
 
Page
Number
PART I. Financial Information
Item 1.
Page
Number
PART I. Financial Information
Item 1.
Financial Statements (Unaudited)
Unaudited Condensed Consolidated Balance Sheets
September
June 30, 20172020 and December 31, 2016
2019
34
Unaudited Condensed Consolidated Statements of Operations

Three and NineSix Months Ended SeptemberJune 30, 20172020 and 2016
2019
56
Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)
Loss
Three and NineSix Months Ended SeptemberJune 30, 20172020 and 2016
2019
67
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
Nine Months Ended September
Six months ended June 30, 20172020 and 20162019
710
912
Item 2.
3053
Item 3.
5476
Item 4.
5677
PART II. Other Information
Item 1.
5678
Item 1A.
5778
Item 2.
5782
Item 3.
5782
Item 4.
5782
Item 5.
5882
Item 6.
5983
6085


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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; and
•our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods.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;
putative class action lawsuits that may result in substantial•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 divert management's attention;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 the date of 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, respectively54,146 82,656 
Materials and supplies110 449 
Current derivative asset (Note 12)0 633 
Current income tax receivable850 1,756 
Assets held for sale (Note 5)0 5,908 
Prepaid expenses and other16,659 13,078 
Total current assets108,759 105,051 
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties6,566,669 6,341,582 
Unproved properties not being amortized30,342 252,874 
Drilling equipment1,296,319 1,295,713 
Gas gathering and processing equipment833,402 824,699 
Saltwater disposal systems43,843 69,692 
Land and building59,080 59,080 
Transportation equipment16,780 29,723 
Other58,036 57,992 
8,904,471 8,931,355 
Less accumulated depreciation, depletion, amortization, and impairment7,903,051 6,978,669 
Net property and equipment1,001,420 1,952,686 
Right of use asset (Note 14)7,828 5,673 
Other assets22,371 26,642 
Total assets (1)
$1,140,378 $2,090,052 
  September 30,
2017		 December 31,
2016
  (In thousands except share amounts)
ASSETS    
Current assets:    
Cash and cash equivalents $822
 $893
Accounts receivable, net of allowance for doubtful accounts of $2,393 and $3,773 at September 30, 2017 and December 31, 2016, respectively 116,292
 83,954
Materials and supplies 3,323
 3,340
Current derivative asset (Note 10) 1,064
 —
Current income tax receivable 114
 99
Current deferred tax asset (Note 8) —
 25,211
Prepaid expenses and other 7,351
 7,699
Total current assets 128,966
 121,196
Property and equipment:    
Oil and natural gas properties on the full cost method:    
Proved properties 5,605,974
 5,446,305
Unproved properties not being amortized 337,064
 314,867
Drilling equipment 1,593,835
 1,565,268
Gas gathering and processing equipment 715,864
 705,859
Saltwater disposal systems 62,387
 60,638
Corporate land and building 59,079
 59,066
Transportation equipment 29,731
 32,842
Other 53,308
 48,590
  8,457,242
 8,233,435
Less accumulated depreciation, depletion, amortization, and impairment 6,099,229
 5,952,330
Net property and equipment 2,358,013
 2,281,105
Goodwill 62,808
 62,808
Non-current derivative asset (Note 10) —
 377
Other assets 16,085
 13,817
Total assets $2,565,872
 $2,479,303














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 0 
Current derivative liabilities (Note 12)5,011 0 
Current portion of other long-term liabilities (Note 8)13,628 17,376 
Total current liabilities213,497 260,049 
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 0 
Deferred income taxes4,750 13,713 
Commitments and contingencies (Note 15)
Shareholders’ equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued0 0 
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, respectively10,704 10,591 
Capital in excess of par value648,128 644,152 
Retained earnings (deficit)(787,008)199,135 
Total shareholders’ equity attributable to Unit Corporation(128,176)853,878 
Non-controlling interests in consolidated subsidiaries168,708 201,757 
Total shareholders' equity40,532 1,055,635 
Total liabilities(1) and shareholders’ equity
$1,140,378 $2,090,052 
  September 30,
2017		 December 31,
2016
  (In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY    
Current liabilities:    
Accounts payable $116,152
 $88,793
Accrued liabilities (Note 5) 60,132
 39,651
Current derivative liability (Note 10) 636
 21,564
Current portion of other long-term liabilities (Note 6) 14,227
 14,907
Total current liabilities 191,147
 164,915
Long-term debt less debt issuance costs (Note 6) 803,833
 800,917
Non-current derivative liability (Note 10) 282
 415
Other long-term liabilities (Note 6) 105,468
 103,064
Deferred income taxes (Note 8) 213,237
 215,922
Commitments and contingencies (Note 12) —
 —
Shareholders’ equity:    
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued —
 —
Common stock, $.20 par value, 175,000,000 shares authorized, 52,879,660 and 51,494,318 shares issued as of September 30, 2017 and December 31, 2016, respectively 10,277
 10,016
Capital in excess of par value 531,328
 502,500
Accumulated other comprehensive income (Note 13) 53
 —
Retained earnings 710,247
 681,554
Total shareholders’ equity 1,251,905
 1,194,070
Total liabilities and shareholders’ equity $2,565,872
 $2,479,303
_______________________

(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 EndedSix Months Ended
 June 30,June 30,
 2020201920202019
 (In thousands except per share amounts)
Revenues:
Oil and natural gas$26,956 $77,815 $75,478 $163,910 
Contract drilling29,202 43,037 65,834 94,192 
Gas gathering and processing32,849 44,294 70,071 96,735 
Total revenues89,007 165,146 211,383 354,837 
Expenses:
Operating costs:
Oil and natural gas71,540 36,242 102,203 68,956 
Contract drilling20,951 29,308 46,400 60,709 
Gas gathering and processing22,612 32,491 50,223 71,846 
Total operating costs115,103 98,041 198,826 201,511 
Depreciation, depletion, and amortization35,960 66,292 97,577 128,418 
Impairments (Note 3)109,318 0 851,242 0 
Loss on abandonment of assets (Note 3)0 0 17,554 0 
General and administrative25,814 10,064 37,367 19,805 
(Gain) loss on disposition of assets877 (422)1,267 1,193 
Total operating expenses287,072 173,975 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 $5.4 million on senior subordinated notes subject to compromise, for the three and six months ended June 30, 2020)(7,608)(8,995)(20,865)(17,533)
Write-off of debt issuance costs (Note 8)(2,426)0 (2,426)0 
Gain (loss) on derivatives (Note 12)(6,937)7,927 (6,454)995 
Reorganization items, net (Note 2)(7,027)0 (7,027)0 
Other, net43 6 103 11 
Total other income (expense)(23,955)(1,062)(36,669)(16,527)
Loss before income taxes(222,020)(9,891)(1,029,119)(12,617)
Income tax benefit:
Current0 0 (917)0 
Deferred(6,455)(1,874)(8,963)(2,318)
Total income tax benefit(6,455)(1,874)(9,880)(2,318)
Net loss(215,565)(8,017)(1,019,239)(10,299)
Net income (loss) attributable to non-controlling interest84 492 (33,096)1,714 
Net loss attributable to Unit Corporation$(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)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
  (In thousands except per share amounts)
Revenues:        
Oil and natural gas $85,470
 $78,854
 $256,241
 $206,318
Contract drilling 51,619
 25,819
 128,059
 88,786
Gas gathering and processing 51,399
 48,735
 150,493
 132,793
Total revenues 188,488
 153,408
 534,793
 427,897
Expenses:        
Operating costs:        
Oil and natural gas 33,911
 26,014
 95,873
 92,691
Contract drilling 34,747
 19,137
 91,213
 66,489
Gas gathering and processing 38,116
 35,738
 111,862
 99,185
Total operating costs 106,774
 80,889
 298,948
 258,365
Depreciation, depletion, and amortization 54,533
 49,969
 151,545
 158,437
Impairments (Note 2) —
 49,443
 —
 161,563
General and administrative 9,235
 8,852
 26,902
 25,811
Gain on disposition of assets (81) (154) (1,153) (823)
Total operating expenses 170,461
 188,999
 476,242
 603,353
Income (loss) from operations 18,027
 (35,591) 58,551
 (175,456)
Other income (expense):        
Interest, net (9,944) (10,002) (28,807) (30,225)
Gain (loss) on derivatives (2,614) 6,969
 21,019
 (4,774)
Other, net 5
 3
 14
 (11)
Total other income (expense) (12,553) (3,030) (7,774) (35,010)
Income (loss) before income taxes 5,474
 (38,621) 50,777
 (210,466)
Income tax expense (benefit):        
Deferred 1,769
 (14,599) 22,084
 (73,159)
Total income taxes 1,769
 (14,599) 22,084
 (73,159)
Net income (loss) $3,705
 $(24,022) $28,693
 $(137,307)
Net income (loss) per common share:        
Basic $0.07
 $(0.48) $0.56
 $(2.75)
Diluted $0.07
 $(0.48) $0.56
 $(2.75)


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 INCOME (LOSS)LOSS (UNAUDITED)
 
Three Months EndedSix Months Ended
 June 30,June 30,
 2020201920202019
 (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 ($2)0 (30)0 (6)
Comprehensive loss(215,565)(8,047)(1,019,239)(10,305)
Less: Comprehensive income (loss) attributable to non-controlling interest84 492 (33,096)1,714 
Comprehensive loss attributable to Unit Corporation$(215,649)$(8,539)$(986,143)$(12,019)
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (In thousands)
Net income (loss)$3,705
 $(24,022) $28,693
 $(137,307)
Other comprehensive income, net of taxes:       
Unrealized appreciation on securities, net of tax of $20, $0, $32, and $033
 —
 53
 —
Comprehensive income (loss)$3,738
 $(24,022) $28,746
 $(137,307)








































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 FLOWSCHANGES IN SHAREHOLDERS’ EQUITY (UNAUDITED)
  Nine Months Ended
  September 30,
  2017 2016
  (In thousands)
OPERATING ACTIVITIES:    
Net income (loss) $28,693
 $(137,307)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation, depletion, and amortization 151,545
 158,437
Impairments (Note 2) —
 161,563
Amortization of debt issuance costs and debt discount (Note 6) 1,616
 1,586
(Gain) loss on derivatives (21,019) 4,774
Cash (payments) receipts on derivatives settled, net (729) 11,735
Deferred tax expense (benefit) 22,084
 (73,159)
Gain on disposition of assets (1,153) (1,100)
Stock compensation plans 12,478
 10,664
Other, net 1,397
 (3,055)
Changes in operating assets and liabilities increasing (decreasing) cash:    
Accounts receivable (36,381) 759
Accounts payable 4,873
 26,940
Material and supplies 17
 231
Accrued liabilities��20,280
 14,073
Income taxes (15) 20,636
Other, net 1,106
 985
Net cash provided by operating activities 184,792
 197,762
INVESTING ACTIVITIES:    
Capital expenditures (167,392) (154,558)
Producing properties and other acquisitions (Note 3) (55,429) —
Proceeds from disposition of assets 20,137
 46,880
Other (1,500) 169
Net cash used in investing activities (204,184) (107,509)
FINANCING ACTIVITIES:    
Borrowings under credit agreement 251,401
 195,700
Payments under credit agreement (250,100) (261,700)
Payments on capitalized leases (2,967) (2,756)
Proceeds from common stock issued, net of issue costs (Note 13) 18,623
 —
Tax benefit from stock compensation —
 (376)
Book overdrafts 2,364
 (21,043)
Net cash provided by (used in) financing activities 19,321
 (90,175)
Net increase (decrease) in cash and cash equivalents (71) 78
Cash and cash equivalents, beginning of period 893
 835
Cash and cash equivalents, end of period $822
 $913


Three Months Ended June 30, 2020
Shareholders' Equity Attributable to Unit Corporation
Common
Stock		Capital in Excess
of Par Value		Accumulated Other Comprehensive IncomeRetained
Deficit		Non-controlling Interest in Consolidated SubsidiariesTotal
(In thousands except per share amounts)
Balances, March 31, 2020$10,694 $646,543 $0 $(571,359)$168,608 $254,486 
Net income (loss)0 0 0 (215,649)84 (215,565)
Activity in employee compensation plans10 1,585 0 0 16 1,611 
Balances, June 30, 2020$10,704 $648,128 $0 $(787,008)$168,708 $40,532 

Supplemental disclosure of cash flow information:    
Cash paid during the year for:    
Interest paid (net of capitalized) 14,601
 16,650
Income taxes —
 —
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment (20,122) 36,934
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations (3,203) 29,423
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 SubsidiariesTotal
 (In thousands except per share amounts)
Balances, December 31, 2019$10,591 $644,152 $0 $199,135 $201,757 $1,055,635 
Net loss0 0 0 (986,143)(33,096)(1,019,239)
Activity in employee compensation plans113 3,976 0 0 47 4,136 
Balances, June 30, 2020$10,704 $648,128 $0 $(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 LossRetained
Earnings		Non-controlling Interest in Consolidated SubsidiariesTotal
(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)0 0 0 (8,509)492 (8,017)
Other comprehensive loss (net of tax of ($9))0 0 (30)0 0 (30)
Total comprehensive loss(8,047)
Activity in employee compensation plans12 5,408 0 0 0 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 SubsidiariesTotal
 (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 ASUs0 0 0 174 0 174 
Net income (loss)0 0 0 (12,013)1,714 (10,299)
Other comprehensive loss (net of tax of ($2))0 0 (6)0 0 (6)
Total comprehensive loss(10,305)
Distributions to non-controlling interest0 0 0 0 (918)(918)
Activity in employee compensation plans176 10,661 0 0 0 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,
 20202019
 (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 amortization97,577 128,418 
Impairments (Note 3)851,242 0 
Loss on abandonment of assets (Note 3)17,554 0 
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 assets1,267 1,193 
Write-off of debt issuance costs2,426 0 
Deferred tax benefit(8,963)(2,318)
Employee stock compensation plans4,179 11,187 
Bad debt expense1,923 0 
ARO liability accretion (Note 9)1,169 1,168 
Contract assets and liabilities, net (Note 4)1,790 (1,283)
Noncash reorganization items7,027 0 
Other, net11,493 (51)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable26,587 26,939 
Material and supplies43 (43)
Prepaid expenses and other(2,703)(377)
Accounts payable(22,876)(30,374)
Accrued liabilities48,244 (1,245)
Income taxes906 0 
Contract advances(21)(848)
Net cash provided by operating activities26,467 127,501 
INVESTING ACTIVITIES:
Capital expenditures(23,804)(246,638)
Producing properties and other acquisitions(210)(3,313)
Proceeds from disposition of property and equipment4,497 7,340 
Net cash used in investing activities(19,517)(242,611)
FINANCING ACTIVITIES:
Borrowings under line of credit, including borrowings under DIP credit facility79,400 271,200 
Payments under line of credit(38,100)(160,200)
DIP financing costs(990)0 
Net payments on finance leases(2,061)(1,980)
Employee taxes paid by withholding shares(43)(4,073)
Distributions to non-controlling interests0 (918)
Bank overdrafts(8,733)5,298 
Net cash provided by financing activities29,473 109,327 
Net increase (decrease) in cash and cash equivalents36,423 (5,783)
Cash and cash equivalents, beginning of year571 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,
 20202019
 (In thousands)
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)$4,795 $15,748 
Income taxes0 0 
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment5,974 (6,260)
Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations3,548 (2,057)
Non-cash trade of property, plant, and equipment548 0 





































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 filed February 28, 2017, for the year ended December 31, 2016.2019, 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 the following:state:


•Balance Sheets at Septemberas of June 30, 20172020 and December 31, 2016;2019;
•Statements of Operations for the three and ninesix months ended SeptemberJune 30, 20172020 and 2016;
2019;
•Statements of Comprehensive Income (Loss)Loss for the three and ninesix months ended SeptemberJune 30, 20172020 and 2016;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 ninesix months ended SeptemberJune 30, 20172020 and 2016.
2019.


Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). 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 ninesix months ended SeptemberJune 30, 20172020 and 20162019 are not necessarily indicative of the results to be realizedwe may realize for the full year of 2017,2020, or that we realized for the full year of 2016.2019.


Certain amounts in the unaudited condensed consolidated financial statementsthis report for prior periods have been reclassified to conform to current year presentation. There wasThe reclassification had no impact to consolidated net income (loss)loss or shareholders' equity.


NOTE 2 – OILCHAPTER 11 PROCEEDINGS, LIQUIDITY, AND NATURAL GAS PROPERTIESABILITY TO CONTINUE AS A GOING CONCERN

FullVoluntary 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 payable735 
Employee separation benefit plan obligations22,624 
Litigation settlements45,000 
Royalty suspense accounts payable19,637 
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 20212,205 
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 receivable33,628 
Intercompany accounts receivable5,290 
Materials and supplies110 
Current income tax receivable850 
Prepaid expenses and other9,338 
Total current assets62,430 
Intercompany investment338,809 
Net property and equipment658,041 
Right of use asset3,337 
Other assets16,626 
Total assets$1,079,243 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable$16,828 
Intercompany accounts payable4,364 
Accrued liabilities25,355 
Current operating lease liability2,154 
Current portion of long-term debt124,000 
Debtor-in-possession financing8,000 
Current derivative liability5,011 
Current portion of other long-term liabilities5,615 
Total current liabilities191,327 
Non-current derivative liabilities145 
Operating lease liability1,146 
Other long-term liabilities81,623 
Liabilities subject to compromise759,720 
Deferred income taxes4,750 
Shareholders’ equity:
Total shareholders’ equity attributable to Unit Corporation(128,176)
Non-controlling interests in consolidated subsidiaries168,708 
Total shareholders' equity40,532 
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, 2020Six Months Ended June 30, 2020
(In thousands)
Revenues$56,159 $141,315 
Expenses:
Operating costs93,305 150,169 
Depreciation, depletion and amortization25,612 74,956 
Impairment109,318 787,280 
Loss on abandonment of assets0 17,554 
General and administrative25,814 37,367 
Loss on disposition of assets886 1,282 
Total operating costs254,935 1,068,608 
Loss from operations(198,776)(927,293)
Other income (expense):
Interest, net(7,066)(19,805)
Write-off of debt issuance costs(2,426)(2,426)
Loss on derivatives(6,937)(6,454)
Reorganization items(7,027)(7,027)
Other, net22 64 
Total other income (expense)(23,434)(35,648)
Loss before income taxes(222,210)(962,941)
Income tax benefit(6,455)(9,880)
Equity in net earnings (losses) from investment188 (66,178)
Net loss(215,567)(1,019,239)
Net income (loss) attributable to non-controlling interest84 (33,096)
Net loss attributable to Unit Corp$(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 amortization74,956 
Impairments787,280 
Loss on abandonment of assets17,554 
Amortization of debt issuance costs and debt discount1,079 
Equity investment in non-debtor subsidiaries66,086 
Loss on derivatives6,454 
Cash receipts on derivatives settled(691)
Loss on disposition of assets1,282 
Write-off of debt issuance costs2,426 
Deferred tax benefit(8,963)
Employee stock compensation plans4,179 
Bad debt expense1,923 
ARO liability accretion1,169 
Noncash reorganization items7,027 
Other, net11,621 
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable26,609 
Material and supplies43 
Prepaid expenses and other(3,158)
Accounts payable(20,958)
Accrued liabilities49,661 
Net cash provided by operating activities6,340 
INVESTING ACTIVITIES:
Capital expenditures(14,188)
Producing properties and other acquisitions(210)
Proceeds from disposition of property and equipment4,422 
Net cash used in investing activities(9,976)
FINANCING ACTIVITIES:
Borrowings under line of credit, including borrowings under DIP credit facility47,300 
Payments under line of credit(23,500)
DIP financing costs(990)
Intercompany borrowings781 
Employee taxes paid by withholding shares(43)
Bank overdrafts(7,269)
Net cash provided by financing activities16,279 
Net increase in cash and cash equivalents12,643 
Cash and cash equivalents, beginning of year571 
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 require us towe 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 referred to ascalled 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 included 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 incurredrecorded 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 0 non-cash ceiling test write-downs in the first ninesix months of 20162019.

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Table of $161.6 million ($100.6 million netContents
In addition to the impairment evaluations of tax). We did not have a write-downour proved and unproved oil and gas properties in the first nine monthsquarter of 2017.2020, 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 34 – ACQUISITIONS AND DIVESTITURESREVENUE FROM CONTRACTS WITH CUSTOMERS


Acquisitions

On April 3, 2017, we closed on an acquisition of certainOur revenue streams are reported under three segments: oil and natural gas, assets located primarilycontract drilling, and mid-stream. This is how we disaggregate our revenue and report our segment revenue (as reflected in GradyNote 17 – Industry Segment Information). Revenue from the oil and Caddo Counties in western Oklahoma. The final adjusted valuenatural gas segment is from sales of consideration given was $54.3 million.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.


As of January 1, 2017, the effective dateOil and Natural Gas Revenues

Certain costs—as either a deduction from revenue or as an expense—are determined based on when control of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas

leasehold acrescommodity is transferred to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. Of the acreage acquired, approximately 71% was held by production. We also received onecustomer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, systemprocessing, and transportation costs included as part of the transaction.

We accounted for this acquisition usingcontract price with the acquisition method under ASC 805, Business Combinations, which requires that the acquired assets and liabilities be recorded at their fair values ascustomer on transfer of control of the acquisition date. 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 following table summarizesimpact from the adjusted purchase pricemobilization and the estimated values of assets acquired and liabilities assumed. It is based on information availablede-mobilization charges due under our outstanding drilling contracts to us at the time these unaudited condensed consolidatedour financial statements were prepared. We believe these estimateswas immaterial. As of June 30, 2020, we had 3 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 reasonable; however,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 estimates are subject to change as additional information becomes availablechanges in our mid-stream contract asset and is assessed by us (in thousands):contract liability balances during the six months ended June 30, 2020:

Adjusted Purchase Price 
Total consideration given$54,332
  
Adjusted Allocation of Purchase Price 
Oil and natural gas properties included in the full cost pool: 
Proved oil and natural gas properties$43,745
Undeveloped oil and natural gas properties8,650
Total oil and natural gas properties included in the full cost pool (1)
52,395
Gas gathering equipment and other2,340
Asset retirement obligation(403)
Fair value of net assets acquired$54,332

(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.
June 30,
2020		December 31,
2019		Change
(In thousands)
Contract assets$9,695 $12,921 $(3,226)
Contract liabilities5,625 7,061 (1,436)
Contract assets (liabilities), net$4,070 $5,860 $(1,790)
The pro forma effectsamounts above are reported in prepaid expenses and other, other assets (long-term), current portion of this acquired businessother long-term liabilities and other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets.

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

ContractRemaining Term of ContractJuly - December
2020		202120222023 and beyondTotal Remaining Impact to Revenue
(In thousands)
Demand fee contracts2-8 years$(1,985)$(3,501)$1,380 $36 $(4,070)
During the third quarter of 2017, we had approximately $2.1 million in other acquisitions.

DivestituresNOTE 5 – DIVESTITURES


Oil and Natural Gas

We sold $0.9 million of non-core oil and natural gas assets, net of related expenses, for $18.0during the first six months of 2020, compared to $2.1 million during the first ninesix months of 2017, compared to $43.6 million during the first nine months of 2016. Proceeds from those sales2019. 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 7 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 0 longer have assets that meet the criteria to be classified as held for sale.

NOTE 46 – EARNINGS (LOSS)LOSS PER SHARE


Information related to the calculation of earnings (loss)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 $(4.03)
Effect of dilutive stock options and restricted stock0 0 0 
Diluted loss attributable to Unit Corporation per common share$(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 $(0.16)
Effect of dilutive stock options and restricted stock0 0 0 
Diluted loss attributable to Unit Corporation per common share$(8,509)52,930 $(0.16)
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Earnings (Loss)
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
  (In thousands except per share amounts)
For the three months ended September 30, 2017      
Basic earnings per common share $3,705
 51,386
 $0.07
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) —
 586
 —
Diluted earnings per common share $3,705
 51,972
 $0.07
For the three months ended September 30, 2016      
Basic loss per common share $(24,022) 50,081
 $(0.48)
Effect of dilutive stock options, restricted stock, and SARs —
 —
 —
Diluted loss per common share $(24,022) 50,081
 $(0.48)


Due to the net loss for the three months ended September 30, 2016, approximately 546,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the calculation above.


The following table shows the number of stock options and SARs (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,
 20202019
Stock options28,000 42,000 
Average exercise price$52.24 $48.56 
  Three Months Ended
  September 30,
  2017 2016
Stock options and SARs 178,755
 240,270
Average exercise price $47.75
 $49.29



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 $(18.50)
Effect of dilutive stock options and restricted stock0 0 0 
Diluted loss attributable to Unit Corporation per common share$(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 $(0.23)
Effect of dilutive stock options and restricted stock0 0 0 
Diluted loss attributable to Unit Corporation per common share$(12,013)52,744 $(0.23)
  Earnings (Loss)
(Numerator)		 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
  (In thousands except per share amounts)
For the nine months ended September 30, 2017      
Basic earnings per common share $28,693
 51,019
 $0.56
Effect of dilutive stock options, restricted stock, and SARs —
 550
 —
Diluted earnings per common share $28,693
 51,569
 $0.56
For the nine months ended September 30, 2016      
Basic loss per common share $(137,307) 50,012
 $(2.75)
Effect of dilutive stock options, restricted stock, and SARs —
 —
 —
Diluted loss per common share $(137,307) 50,012
 $(2.75)

Because of the net loss for the nine months ended September 30, 2016, approximately 424,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the calculation above.

The following table shows the number of stock options and SARs (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,
 20202019
Stock options28,000 42,000 
Average exercise price$52.24 $48.56 

  Nine Months Ended
  September 30,
  2017 2016
Stock options and SARs 178,755
 240,270
Average exercise price $47.75
 $49.29

NOTE 57 – ACCRUED LIABILITIES


Accrued liabilities consisted of:
June 30,
2020		December 31,
2019
 (In thousands)
Employee costs$7,016 $17,832 
Lease operating expenses6,651 9,200 
Taxes6,343 3,450 
Third-party credits2,167 3,691 
Derivative settlements1,323 0 
Interest payable760 6,562 
Other7,124 5,827 
Total accrued liabilities$31,384 $46,562 
24
  September 30,
2017		 December 31,
2016
  (In thousands)
Interest payable $17,480
 $6,524
Employee costs 14,526
 15,394
Lease operating expenses 12,686
 10,075
Taxes 9,982
 2,219
Third-party credits 2,184
 2,998
Other 3,274
 2,441
Total accrued liabilities $60,132
 $39,651
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NOTE 68 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES


Long-Term Debt


OurThe 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 of the dates indicatedliabilities 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, 20208,000 0 
Total current portion of long-term debt132,000 108,200 
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, respectively34,000 16,500 
6.625% senior subordinated notes due 20210 650,000 
Total principal amount34,000 666,500 
Less: unamortized discount0 (971)
Less: debt issuance costs, net0 (2,313)
Total long-term debt$34,000 $663,216 
  September 30,
2017		 December 31,
2016
  (In thousands)
Credit agreement with an average interest rate of 3.3% and 2.8% at September 30, 2017 and December 31, 2016, respectively $162,100
 $160,800
6.625% senior subordinated notes due 2021 650,000
 650,000
Total principal amount 812,100
 810,800
Less: unamortized discount (2,380) (2,804)
Less: debt issuance costs, net (5,887) (7,079)
Total long-term debt $803,833
 $800,917


Unit Credit Agreement. Our Senior 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 (credit agreement) is scheduled to mature on April 10, 2020. UnderExtension 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 amount we can borrow isCredit Agreement Extension Condition was based on the lesserfiling of the amountChapter 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 elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed $875.0 million. Our borrowing base and elected commitment is $475.0 million. We arewere charged a commitment fee of 0.50%0.375% on the amount available but not borrowed. That fee variesvaried based on the amount borrowed as a percentage of the total borrowing base. We paid $1.0Total amendment fees of $3.3 million in origination, agency, syndication, and other related fees. We are amortizing these 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 the following collateral: (a) 85%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, and (b) 100%UPC also pledged as collateral certain items of our ownershipits 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 mid-stream affiliate, Superior Pipeline Company, L.L.C.

The borrowing base amount–which is subject to redetermination byobligations under the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. The October 2017 redetermination did not result in any changes. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in theUnit credit agreement.


At our election,Before filing the Chapter 11 Cases, any part of the outstanding debt under the Unit credit agreement maycould be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base for the term plus 2.00%1.50% to 3.00%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 atequal to the higher of the prime rate specified in the Unit credit agreement that cannotand 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. At September 30, 2017, we had $162.1 million

Filing the Bankruptcy Petitions on May 22, 2020 constituted an event of outstanding borrowingsdefault that accelerated the company’s obligations under our credit agreement.

We can use borrowings for financing general working capital requirements for (a) exploration, development, production, and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services and acquisition of contract drilling equipment, and (e) general corporate purposes.

Thethe Unit credit agreement, prohibits, among other things:

and the paymentlenders’ rights of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income forenforcement regarding the preceding fiscal year;
the incurrence of additional debt with certain limited exceptions; and
the creation or existence of mortgages or liens, other than those in the ordinary course of business and with certain limited exceptions, on any of our properties, except in favor of our lenders.

TheUnit credit agreement also requireswere automatically stayed because of the Chapter 11 Cases.

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 we havelender’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 endapplicable margin of each quarter:

a current ratio2.00% 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 credit agreement) of not less than 1 to 1.

Through the quarter ending March 31, 2019, theSuperior credit agreement alsoplus 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 we have at the end of each quarter:

Superior maintain a senior indebtednessConsolidated EBITDA to interest expense ratio of senior indebtedness to consolidated EBITDA (as defined in the credit agreement) for the most recentlymost-recently ended rolling four quarters of no greater than 2.75at least 2.50 to 1.

Beginning with the quarter ending June 30, 2019,1.00, and for each following quarter, the credit agreement requires:

a leverage ratio of funded debt to consolidatedConsolidated EBITDA (as definedratio 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 credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.Chapter 11 Cases.


As of September 30, 2017, we were in compliance with the credit agreement covenants.

6.625% Senior Subordinated Notes. We have As of June 30, 2020, we had an aggregate principal amount of $650.0 million 6.625% senior subordinated notes (the Notes) outstanding.outstanding on the Notes. Interest on the Notes iswas payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes were scheduled to mature on May 15, 2021.2021. In issuing the Notes, we incurred fees of $14.7 million that arewere being amortized as debt issuance cost overuntil maturity. In the lifesecond quarter of 2020, we wrote off the remaining debt issuance costs of $2.2 million due to the filing of the Notes.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 arewere subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the 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. The Guarantors are most of our direct and indirect subsidiaries. The discussionOn the Effective Date, by operation of the Plan, all outstanding obligations under the Notes in this report is qualified by and subject to the actual termswere cancelled.
26
Table of the 2011 Indenture.Contents


Unit, as the parent company,other than its ownership in its subsidiaries, has no significant independent assets or operations. The guarantees by the Guarantors of the Notes
(registered (registered under registration statements) arewere 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. AnySuperior was not a Guarantor of the Notes as of the Petition Date. Excluding Superior, any of our other subsidiaries that arewere not Guarantors arewere minor. There are no significant restrictions on our ability to receive funds from any of our subsidiariessubsidiary through dividends, loans, advances, or otherwise.


We may redeem all or, occasionally,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 part30-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 at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchasewere stayed from each holder alltaking any action against the company or any part of that holder’s Notes at a purchase price in cash equal to 101%the other Debtors because of the principal amountdefault. Pursuant to the Plan, each holder of the Notes plus accruedwill receive its pro rata share of New Common Stock based on equity allocations at each of Unit, UDC and unpaid interestUPC 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 purchase. The 2011 Indenture contains customary eventstermination of default. The 2011 Indenture also contains covenants including those that limit our abilitythe DIP Lenders’ commitments and the abilityacceleration of certainany outstanding extensions of our subsidiariescredit, in each case, under the DIP credit facility under and subject to incur or guarantee additional indebtedness; pay dividendsthe 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 our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenantsthe 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 NotesNew 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.

27
Table of September 30, 2017.Contents



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’ compensation12,112 11,510 
Finance lease obligations5,319 7,379 
Contract liability5,625 7,061 
Separation benefit plans (1)
0 10,122 
Deferred compensation plan6,006 6,180 
Gas balancing liability3,823 3,838 
Other long-term liability1,217 0 
98,350 112,717 
Less current portion13,628 17,376 
Total other long-term liabilities$84,722 $95,341 
  September 30,
2017		 December 31,
2016
  (In thousands)
Asset retirement obligation (ARO) liability $75,485
 $70,170
Capital lease obligations 16,161
 18,918
Workers’ compensation 13,420
 15,163
Separation benefit plans 6,020
 4,943
Deferred compensation plan 5,287
 4,578
Gas balancing liability 3,322
 3,789
Other —
 410
  119,695
 117,971
Less current portion 14,227
 14,907
Total other long-term liabilities $105,468
 $103,064
_______________________

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 monthtwelve-month periods beginning OctoberJuly 1, 20172020 (and through 2022)2024) are $14.2$145.6 million, $48.3$5.6 million, $172.4$2.8 million, $657.0$36.2 million, and $2.5$2.3 million, respectively.

Capital Leases

In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms The Debtors' filing of seven years. The underlying assetsthe Bankruptcy Petitions constituted an event of default that accelerated the Debtors' obligations under the Unit credit agreement, which are included in gas gathering and processing equipment. The $3.8 millionreflected as current portion of our capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $12.4 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of SeptemberJune 30, 2017. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $6.3 million and $1.3 million, respectively, at September 30, 2017. Annual payments, net of maintenance and interest, average $4.1 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value.2020.


Future payments required under the capital leases at September 30, 2017:
  Amount
Beginning October 1, (In thousands)
2017 $6,168
2018 6,168
2019 6,168
2020 5,310
Total future payments 23,814
Less payments related to:  
Maintenance 6,320
Interest 1,333
Present value of future minimum payments $16,161


NOTE 79 – 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,
 20202019
 (In thousands)
ARO liability, January 1:$66,627 $64,208 
Accretion of discount1,169 1,168 
Liability incurred460 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 portion1,104 1,784 
Total long-term ARO$63,144 $65,649 
  Nine Months Ended
  September 30,
  2017 2016
  (In thousands)
ARO liability, January 1: $70,170
 $98,297
Accretion of discount 2,112
 2,147
Liability incurred 1,123
 311
Liability settled (1,350) (874)
Liability sold (1)
 (1,563) (10,758)
Revision of estimates (2)
 4,993

(18,102)
ARO liability, September 30: 75,485
 71,021
Less current portion 2,947
 3,498
Total long-term ARO $72,538
 $67,523
_______________________ 
(1)We sold our interest in a number of non-core wells to unaffiliated third-parties during the first nine months of 2017 and 2016, respectively.
(2)Plugging liability estimates were revised in both 2017 and 2016 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

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 810 – NEW ACCOUNTING PRONOUNCEMENTS


Compensation—Stock Compensation. 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 2017-09,2016-13 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 clarifythe 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 reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms and conditions of a share-based payment award.other disclosures were added. The amendments areamendment is effective for reporting periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements.

Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. 2019. The FASB issued ASU 2017-04, to simplify the subsequent measurementadoption of goodwill. The amendments eliminate Step 2 from the goodwill impairment test. The amendments will be effective prospectively for reporting periods beginning after December 31, 2019, and early adoption is permitted. We do not believe these amendments will have a material impact on our financial statements.

Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments.  The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. The amendments will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. We do not believe these amendments will have a material impact on our financial statements.

Leases. The FASB has issued ASU 2016-02. The amendments will require lessees to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendments are effective for annual periods beginning after

December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases of mineral rights. We are in the process of evaluating the impact these amendments will have on our financial statements.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. These amendments affect any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the amendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 has been amended several times pre-issuance, which will be codified in the new Topic 606, and it is effective January 1. 2018. Thethis guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. We will adopt these amendments January 1, 2018.

The new revenue standard provides a five-step analysis of transactions to determine the amount and timing of revenue recognition. Entities can choose to apply Topic 606 using either the full retrospective approach or a modified retrospective approach. We plan to adopt using the modified retrospective approach, which will result in a cumulative effect adjustment upon adoption.

Currently, management believes the effect of adoption will not have a material effect on our statement of operations or our balance sheet, as the timing of revenue recognized will not be materially modified, but the adoption will result in more robust footnote disclosures in regards to revenue. We anticipate a cumulative effect of applying the new revenue standard as an adjustment to the opening balance of retained earnings at the beginning of 2018 in relation to certain mid-stream segment and contract drilling segment contracts that include adjustments to the timing of revenue recognition of certain demand fee and mobilization/demobilization expenses and revenue, respectively. We believe this adjustment will not be material due to the short-term nature of the majority of our current contract drilling segment contracts and the limited number of mid-stream segment contracts with demand fees that we anticipate to be in place at the adoption date. Part of our review included evaluation of the following issues:

Based on an analysis of whether the transportation of gas is a performance obligation that occurs at a point in time or over time, the timing of when we recognize certain revenue elements will change. Specifically related to our mid-stream segment, certain fees that are collectible in the early stages of a contract will be recognized over the life of the contract because these fees are part of the single performance obligation associated with the contract.

Certain of our contracts include promises to deliver a minimum volume of commodity to the customer over a defined period of time. If we do not meet this commitment, a deficiency fee is payable to the customer. Topic 606 requires that these types of arrangements represent variable consideration related to the sale of the commodity, and requires that we include an estimate of any deficiency fees expected within revenue, rather than as operating costs. In addition, we will also be required to analyze fees that are billable for deficiencies in minimum volume commitments from customers for our mid-stream segment. In these instances, we will assess the likelihood of earning these fees each reporting period based on the customer’s performance and recognize variable revenue at the time it is not expected to be subject to a significant reversal.

Adopted Standards

Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations are required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments were effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments require current deferred tax assets to be combined with noncurrent deferred tax assets. We have adopted this ASU during the first quarter of 2017 on a prospective basis. Previously, we had a net current deferred tax asset which is now netted with our noncurrent deferred tax liability. Prior periods were not retrospectively adjusted.

Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments primarily

impact classification within the statement of cash flows between financial and operating activities. This did not have a material impact on our consolidated financial statements.statements or related disclosures.


NOTE 9 –STOCK-BASED11 – STOCK-BASED COMPENSATION


ForOn 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, we had:for the time periods shown:
Three Months EndedSix Months Ended
June 30,June 30,
2020201920202019
(In millions)
Recognized stock compensation expense$1.6 $4.7 $4.1 $8.5 
Capitalized stock compensation cost for our oil and natural gas properties0 0.7 0 1.3 
Tax benefit on stock-based compensation0.4 1.2 1.0 2.1 
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
  (In millions)
Recognized stock compensation expense $3.2
 $1.9
 $9.0
 $7.2
Capitalized stock compensation cost for our oil and natural gas properties 0.5
 0.4
 1.3
 1.6
Tax benefit on stock based compensation 1.2
 0.7
 3.4
 2.7

The remaining unrecognized compensation cost related to unvested awards at Septemberas of June 30, 20172020 is approximately $14.2 million, of which $1.7 million is anticipated to be capitalized.$5.7 million. The weighted average period over which this cost will be recognized is one year.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) as well asand to non-employee directors. A total of 7,000,000There are 7,230,000 shares of the company's common stock is 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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Table of Contents
We did not grant any SARs or stock options during either of the three or ninesix month periods ending SeptemberJune 30, 20172020 or 2016.2019. We did not grant any restricted stock awards during either of the three or six month periods ending SeptemberJune 30, 2017 or 2016. The following2020. This table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated:


 Nine Months Ended Nine Months EndedThree Months Ended
 September 30, 2017 September 30, 2016June 30, 2019
 
Time
Vested
 Performance Vested 
Time
Vested
 Performance Vested Time
Vested		Performance Vested
Shares granted:        Shares granted:
Employees 475,799
 173,373
 486,578
 152,373
Employees1,500 0 
Non-employee directors 49,104
 —
 90,000
 —
Non-employee directors72,784 0 
 524,903
 173,373
 576,578
 152,373
74,284 0 
Estimated fair value (in millions):(1)
        
Estimated fair value (in millions):(1)
Employees $11.8
 $4.5
 $2.6
 $0.8
Employees$0 $0 
Non-employee directors 0.9
 —
 0.9
 —
Non-employee directors0.9 0 
 $12.7
 $4.5
 $3.5
 $0.8
$0.9 $0 
Percentage of shares granted expected to be distributed:        Percentage of shares granted expected to be distributed:
Employees 95% 91% 94% 89%Employees95 %N/A
Non-employee directors 100% N/A
 100% N/A
Non-employee directors100 %N/A
_______________________
(1)Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

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:
Employees927,173 424,070 
Non-employee directors72,784 0 
999,957 424,070 
Estimated fair value (in millions): (1)
Employees$14.6 $7.1 
Non-employee directors0.9 0 
$15.5 $7.1 
Percentage of shares granted expected to be distributed:
Employees95 %54 %
Non-employee directors100 %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 ninesix months of 2017 and 20162019 are being recognized over a three-yearthree-year vesting period. During the first two quarters of 2017 and the first quarter of 2016, there were2019, two different performance vested restricted stock awards were granted to certain executive officers. The first will cliff vest 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 will vest,vests, one-third each year, over a

three-yearthree-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 SeptemberJune 30, 2017,2020, the participants are estimatednot expected to receive 81% ofany performance-based shares. We expense the 2017, 153% of the 2016, and 40% of the 2015 performance based shares. The CFTA performance measurement at September 30, 2017 was assessed to vestaward at target or 100%. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2017 awards for the first nine months

30
Table of 2017 was $5.8 million.Contents

NOTE 1012 – DERIVATIVES


Commodity Derivatives


We have entered intosigned 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 SeptemberJune 30, 2017,2020, these hedges made up our derivative transactions were comprised of the following hedges:transactions:


•Basis/Differential Swaps.We receive or pay a fixed price for the commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Basis 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 basisbasis/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 for speculative purposes.not otherwise tied to our projected production. Any changes in the fair value of our derivative transactions occurring before maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations.


At SeptemberAs of June 30, 2017, the following2020, these derivatives were outstanding:
TermCommodityContracted Volume
Weighted Average��
Average 
Fixed Price
Contracted Market
Oct'17Jul'20 - Dec'20Natural gas –- basis swap70,00030,000 MMBtu/day$3.038(0.275)IF – NYMEX (HH)NGPL TEXOK
Nov’17 – Dec'17Jul'20 - Dec'20Natural gas –- basis swap60,00020,000 MMBtu/day$2.960(0.455)IF – NYMEX (HH)PEPL
Jan’18 – Dec'18Jan'21 - Dec'21Natural gas –- basis swap20,00030,000 MMBtu/day$3.013(0.215)IF – NYMEX (HH)NGPL TEXOK
Nov’17 – Dec'17Jul'20 - Dec'20Natural gas – basis swap20,000 MMBtu/day$(0.215)IF – NYMEX (HH)
Jan’18 – Mar'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Nov’18 – Dec'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Oct'17Natural gas – collar20,000 MMBtu/day$2.88 - $3.10IF – NYMEX (HH)
Oct'17Natural gas – three-way collar15,00030,000 MMBtu/day$2.50 - $2.00$2.20 - $3.32$2.80IF –- NYMEX (HH)
Nov’17 – Dec'17Jul'20 - Sep'20Natural gas – three-way collar25,000 MMBtu/day$2.90 - $2.30 - $3.59IF – NYMEX (HH)
Jan'18 – Mar'18Natural gas – three-way collar60,000 MMBtu/day$3.29 - $2.63 - $4.07IF – NYMEX (HH)
Apr'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Oct’17 – Dec'17Crude oil – three-way- collar3,750112,000 Bbl/daymonth$49.7920.00 - $39.58$26.50WTI - $60.98WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar2,000 Bbl/day$47.50 - $37.50 - $56.08WTI – NYMEX
Jan'18 – Dec'18Crude oil – swap2,000 Bbl/day$50.140WTI – NYMEX

After September 30, 2017, the following derivative was entered into:
TermCommodityContracted Volume
Weighted Average 
Fixed Price
Contracted Market
Apr'18 – Oct'18Natural gas – swap10,000 MMBtu/day$2.990IF – NYMEX (HH)
Apr'18 – Sep'18
Liquids – swap (1)
1,000 Bbl/day$31.164OPIS – Mont Belvieu
_______________________
(1)    Type of liquid involved is propane.


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 LocationJune 30,
2020		December 31,
2019
  (In thousands)
Commodity derivatives:
CurrentCurrent derivative asset$0 $633 
Long-termNon-current derivative asset0 0 
Total derivative assets$0 $633 

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   Derivative Assets  Derivative Liabilities
   Fair Value  Fair Value
 Balance Sheet Location September 30,
2017		 December 31,
2016		 Balance Sheet LocationJune 30,
2020		December 31,
2019
   (In thousands)  (In thousands)
Commodity derivatives:    Commodity derivatives:
Current Current derivative asset $1,064
 $—
CurrentCurrent derivative liability$5,011 $0 
Long-term Non-current derivative asset —
 377
Long-termNon-current derivative liability145 27 
Total derivative assets $1,064
 $377
Total derivative liabilitiesTotal derivative liabilities$5,156 $27 

    Derivative Liabilities
    Fair Value
  Balance Sheet Location September 30,
2017		 December 31,
2016
    (In thousands)
Commodity derivatives:      
Current Current derivative liability $636
 $21,564
Long-term Non-current derivative liability 282
 415
Total derivative liabilities   $918
 $21,979



All of our counterparties are subject to master netting arrangements. If we have 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.


Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the three months ended September 30:periods indicated:
Derivatives Instruments 
Location of Gain (Loss) Recognized in
Income on Derivative
 
Amount of Gain 
(Loss) Recognized in Income on Derivative
    2017 2016
    (In thousands)
Commodity derivatives 
Gain (loss) on derivatives (1)
 $(2,614) $6,969
Total   $(2,614) $6,969
_______________________
(1)Amounts settled during the 2017 and 2016 periods include net proceeds of $0.8 million and net payments of $0.5 million, respectively.

Three Months EndedSix Months Ended
June 30,June 30,
2020201920202019
 (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 
Following is
The commencement of the effect ofChapter 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 Unaudited Condensed Consolidated Statementsoccurrence of Operations for the nine months ended September 30:this termination event (or otherwise).
Derivatives Instruments 
Location of Gain (Loss) Recognized in
Income on Derivative
 Amount of Gain (Loss) Recognized in Income on Derivative
    2017 2016
    (In thousands)
Commodity derivatives 
Gain (loss) on derivatives (1)
 $21,019
 $(4,774)
Total   $21,019
 $(4,774)
_______________________
(1)Amounts settled during the 2017 and 2016 periods include net payments of $0.7 million and net proceeds of $11.7 million, respectively.


NOTE 1113 – FAIR VALUE MEASUREMENTS

The estimated fair value of our available-for-sale securities, reflected on our Unaudited Condensed Consolidated Balance Sheets as Non-current other assets, is based on market quotes. The following is a summary of available-for-sale securities:

  Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value
  (In thousands)
Equity Securities:  
September 30, 2017 $830
 $85
 $—
 $915
December 31, 2016 $—
 $—
 $—
 $—

During the second quarter of 2017, we received available-for-sale securities for early termination fees associated with a long-term drilling contract. We will evaluate the marketable equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge will be recorded and a new cost basis established. We will review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer, and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value.


Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer oftransferring 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 which are 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 2Level 3Effect
of Netting		Net Amounts Presented
 
Financial assets (liabilities):
Commodity derivatives:
Assets$0 $843 $(843)$0 
Liabilities(5,999)0 843 (5,156)
Total commodity derivatives$(5,999)$843 $0 $(5,156)
  September 30, 2017
  Level 1 Level 2 Level 3 
Effect
of Netting
 Net Amounts Presented
  (In thousands)
Financial assets (liabilities):          
Commodity derivatives:          
Assets $—
 $662
 $1,964
 $(1,562) $1,064
Liabilities —
 (2,002) (478) 1,562
 (918)
Total commodity derivatives —
 (1,340) 1,486
 —
 146
Equity securities 915
 —
 —
 —
 915
  $915
 $(1,340) $1,486
 $—
 $1,061

 December 31, 2019
 Level 2Level 3Effect
of Netting		Net Amounts Presented
 
Financial assets (liabilities):
Commodity derivatives:
Assets$177 $1,204 $(748)$633 
Liabilities(775)0 748 (27)
Total commodity derivatives$(598)1,204 0 606 
  December 31, 2016
  Level 1 Level 2 Level 3 
Effect
of Netting
 Net Amounts Presented
  (In thousands)
Financial assets (liabilities):          
Commodity derivatives:          
Assets $—
 $878
 $43
 $(544) $377
Liabilities —
 (15,358) (7,165) 544
 (21,979)
  $—
 $(14,480) $(7,122) $—
 $(21,602)


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 no0 collateral has been posted as of SeptemberJune 30, 2017.2020.



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 1 Fair Value Measurements

Equity Securities. We measure the fair values of our available for sale securities based on market quotes.


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 collars and 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 levelLevel 3 fair value measurements:
 Net Derivatives
Three Months EndedSix Months Ended
June 30,June 30,
 2020201920202019
 (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)
  Net Derivatives
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
  (In thousands)
Beginning of period $4,093
 $(4,761) $(7,122) $9,094
Total gains or losses (realized and unrealized):        
Included in earnings (1)
 (2,015) 3,077
 9,102
 (3,257)
Settlements (592) (443) (494) (7,964)
End of period $1,486
 $(2,127) $1,486
 $(2,127)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period $(2,607) $2,634
 $8,608
 $(11,221)
_______________________
_______________________
1.Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives.
(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 SeptemberJune 30, 2017:2020:
Commodity (1)
 Fair Value Valuation Technique Unobservable Input Range
  (In thousands)      
Oil three-way collars $(9) Discounted cash flow Forward commodity price curve ($3.65) - $5.02
Natural gas collar $25
 Discounted cash flow Forward commodity price curve ($0.11) - $0.06
Natural gas three-way collars $1,470
 Discounted cash flow Forward commodity price curve ($0.34) - $0.54
 _______________________
Commodity (1)
The commodity contracts detailed in this category include non-exchange-traded crude oil and naturalFair ValueValuation TechniqueUnobservable InputRange
(In thousands)
Natural gas collars and three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high$843 Discounted cash flowForward commodity price expected to be paid or received within the settlement period.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 SeptemberJune 30, 20172020 reflected that the risk of non-performance by our counterparties was immaterial.


Fair Value of Other Financial Instruments


The followingThis disclosure of the estimated fair value of financial instruments is made in accordance withunder accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and certain valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use ofUsing different market assumptions or valuation methodologies may have a material effect on theour estimated fair value amounts.



At SeptemberJune 30, 2017,2020, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (classified(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.


Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at September 30, 2017 and December 31, 2016 was $162.1 million and $160.8 million, respectively. This debt would be classified as Level 2.

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 September 30, 2017 and December 31, 20162019 were $641.7 million and $640.1 million, respectively. We estimate$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 markedmarket prices at SeptemberJune 30, 20172020 and December 31, 20162019 was $654.6$100.4 million and $649.9$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 the Company’sour AROs is presented in Note 79 – 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 leases2,061 1,980 
Lease liabilities recognized in exchange for new operating lease right of use assets0 5 

The following table shows information about our lease assets and liabilities in our Unaudited Condensed Consolidated Balance Sheets:
Classification on the Consolidated Balance SheetsJune 30,
2020		December 31,
2019
(In thousands)
Assets
Operating right of use assetsRight of use assets$7,828 $5,673 
Finance right of use assetsProperty, plant, and equipment, net16,455 17,396 
Total right of use assets$24,283 $23,069 
Liabilities
Current liabilities:
Operating lease liabilitiesCurrent operating lease liabilities$4,666 $3,430 
Finance lease liabilitiesCurrent portion of other long-term liabilities5,157 4,164 
Non-current liabilities:
Operating lease liabilitiesOperating lease liabilities3,012 2,071 
Finance lease liabilitiesOther long-term liabilities162 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 EndedSix 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 liabilities60 100 130 211 
Operating lease cost1,395 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, respectively2,751 12,038 6,742 22,012 
Variable lease cost83 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 leases1.64.81%
Finance leases1.24.00%
_______________________
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 
20222,786 
2023222 
202423 
202512 
2025 and beyond70 
Total future payments8,051 
Less: Interest373 
Present value of future minimum operating lease payments7,678 
Less: Current portion4,666 
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 
2021179 
Total future payments6,871 
Less payments related to:
Maintenance1,430 
Interest122 
Present value of future minimum finance lease payments5,319 
Less: Current portion5,157 
Total long-term finance lease payments$162 

NOTE 1215 – COMMITMENTS AND CONTINGENCIES


We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, PennsylvaniaOn May 22, 2020, the Debtors filed the Bankruptcy Petitions seeking relief under the terms of operating leases expiring through December 2021. We also have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.Future minimum rental payments under the termsBankruptcy Code. The commencement of the leases are approximately $3.2 million, $0.8 million, $0.4 million, $0.3 million, and less than $0.1 million in twelve month periods beginning October 1, 2017 (and through the end of 2021), respectively. Total rent expense incurred was $6.4 million and $8.7 million for the first nine months of 2017 and 2016, respectively.

In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the four successive twelve month periods beginning October 1, 2017 (and through the end of 2021) are $6.2 million, $6.2 million, $6.2 million, and $5.3 million. Total maintenance and interest remaining related to these leases are $6.3 million and $1.3 million, respectively at September 30, 2017. Annual payments, net of maintenance and interest, average $4.1 million annually through 2021. At the endChapter 11 Cases automatically stayed all of the term, our mid-stream segment hasproceedings and actions against the option to purchaseDebtors (other than certain regulatory enforcement matters). The Debtors emerged from the assets at 10% of their then fair market value.

The employee oil and gas limited partnerships require,Chapter 11 Cases on the election ofEffective Date. For further information on the Chapter 11 Cases, please see Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal. In any one year, these repurchases are limited to 20% of the units outstanding. We had no repurchases in the first nine months of 2016. We made repurchases of $2,900 during the first nine months of 2017.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 have beenwere resolved while the drilling rig iswas on the location and the cost has been includedlocation. 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 committeddetermined that Superior is a VIE. The two variable interests applicable to purchase approximately $3.9 millionUnit 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 new drilling rig components.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.
NOTE 13 – EQUITY

At-the-Market (ATM) Common Stock Program


On April 4, 2017, we entered into a Distributionthe sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements.

The Agreement (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 sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offeringsale event (both as defined in Rule 415 promulgated under the Securities ActAgreement). 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 1933, as amended, including salesfuture 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 directly onto Unit . At June 30, 2020, if Superior were to be liquidated for its carrying value of assets and liabilities disclosed below and the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subjectliquidating distribution made to the termspartners, we estimate approximately 100% of that liquidating distribution would be distributed to SP Investor Holdings, LLC and conditions ofnothing would be distributed to Unit based upon the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions that we may impose).
We are not obligated to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent7% Liquidation IRR Hurdle. At June 30, 2020, a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
As of September 30, 2017, we sold 787,547 shares of our common stockSales Event resulting in net proceeds of approximately $18.6 million.$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.


Accumulated Other Comprehensive IncomeAs 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.


ComponentsThe carrying value of accumulated other comprehensive incomeSuperior's assets and liabilities, after eliminations of any intercompany transactions and balances, in the consolidated balance sheets were as follows for the three months ended September 30:
  2017 2016
  (In thousands)
Unrealized appreciation on securities, before tax $53
 $—
Tax expense (20) —
Unrealized appreciation on securities, net of tax $33
 $—

Changes in accumulated other comprehensive income by component, net of tax, for the three months ended September 30 are as follows:
June 30,
2020		December 31,
2019
 (In thousands)
Current assets:
Cash and cash equivalents$23,780 $0 
Accounts receivable18,718 21,073 
Prepaid expenses and other7,321 7,686 
Total current assets49,819 28,759 
Property and equipment:
Gas gathering and processing equipment833,402 824,699 
Transportation equipment3,363 3,390 
836,765 828,089 
Less accumulated depreciation, depletion, amortization, and impairment493,386 407,144 
Net property and equipment343,379 420,945 
Right of use asset4,542 3,948 
Other assets6,054 9,442 
Total assets$403,794 $463,094 
Current liabilities:
Accounts payable$9,980 $18,511 
Accrued liabilities4,648 4,198 
Current operating lease liability2,518 2,407 
Current portion of other long-term liabilities8,059 7,060 
Total current liabilities25,205 32,176 
Long-term debt34,000 16,500 
Operating lease liability1,911 1,404 
Other long-term liabilities3,811 8,126 
Total liabilities$64,927 $58,206 

  Net Gains on Equity Securities
  2017 2016
  (In thousands)
Balance at July 1: $20
 $—
Unrealized appreciation before reclassifications 33
 —
Amounts reclassified from accumulated other comprehensive income —
 —
Net current-period other comprehensive income 33
 —
Balance at September 30: $53
 $—


Components of accumulated other comprehensive income were as follows for the nine months ended September 30:
  2017 2016
  (In thousands)
Unrealized appreciation on securities, before tax $85
 $—
Tax expense (32) —
Unrealized appreciation on securities, net of tax $53
 $—

Changes in accumulated other comprehensive income by component, net of tax, for the nine months ended September 30 are as follows:
  Net Gains on Equity Securities
  2017 2016
  (In thousands)
Balance at January 1: $—
 $—
Unrealized appreciation before reclassifications 53
 —
Amounts reclassified from accumulated other comprehensive income —
 —
Net current-period other comprehensive income 53
 —
Balance at September 30: $53
 $—

NOTE 1417 – INDUSTRY SEGMENT INFORMATION


We have three3 main business segments offering different products and services within the energy industry:
 
•Oil and natural gas,
•Contract drilling, and
Mid-stream
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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 September 30, 2017
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues:            
Oil and natural gas $85,470
 $—
 $—
 $—
 $—
 $85,470
Contract drilling —
 55,588
 —
 —
 (3,969) 51,619
Gas gathering and processing —
 —
 69,057
 —
 (17,658) 51,399
Total revenues 85,470
 55,588
 69,057
 —
 (21,627) 188,488
Expenses:            
Operating costs:            
Oil and natural gas 35,082
 —
 —
 —
 (1,171) 33,911
Contract drilling —
 38,115
 —
 —
 (3,368) 34,747
Gas gathering and processing —
 —
 54,602
 —
 (16,486) 38,116
Total operating costs 35,082
 38,115
 54,602
 —
 (21,025) 106,774
Depreciation, depletion, and amortization 26,460
 15,280
 10,880
 1,913
 —
 54,533
Total expenses 61,542
 53,395
 65,482
 1,913
 (21,025) 161,307
Total operating income (loss) (1)
 23,928
 2,193
 3,575
 (1,913) (602)  
General and administrative expense —
 —
 —
 (9,235) —
 (9,235)
Gain (loss) on disposition of assets (1) 68
 14
 —
 —
 81
Loss on derivatives —
 —
 —
 (2,614) —
 (2,614)
Interest expense, net —
 —
 —
 (9,944) —
 (9,944)
Other —
 —
 —
 5
 —
 5
Income (loss) before income taxes $23,927
 $2,261
 $3,589
 $(23,701) $(602) $5,474
_______________________
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes.


Three Months Ended June 30, 2020
 Three Months Ended September 30, 2016 Oil and Natural GasContract DrillingMid-streamCorporate and OtherEliminationsTotal Consolidated
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands)
 (In thousands)
Revenues:            
Revenues: (1)
Revenues: (1)
Oil and natural gas $78,854
 $—
 $—
 $—
 $—
 $78,854
Oil and natural gas$26,957 $0 $0 $0 $(1)$26,956 
Contract drilling —
 25,819
 —
 —
 —
 25,819
Contract drilling0 29,202 0 0 0 29,202 
Gas gathering and processing —
 —
 63,090
 —
 (14,355) 48,735
Gas gathering and processing0 0 37,719 0 (4,870)32,849 
Total revenues 78,854
 25,819
 63,090
 —
 (14,355) 153,408
Total revenues26,957 29,202 37,719 0 (4,871)89,007 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 27,710
 —
 —
 —
 (1,696) 26,014
Oil and natural gas72,354 0 0 0 (814)71,540 
Contract drilling —
 19,137
 —
 —
 —
 19,137
Contract drilling0 20,951 0 0 0 20,951 
Gas gathering and processing —
 —
 48,397
 —
 (12,659) 35,738
Gas gathering and processing0 0 26,669 0 (4,057)22,612 
Total operating costs 27,710
 19,137
 48,397
 —
 (14,355) 80,889
Total operating costs72,354 20,951 26,669 0 (4,871)115,103 
Depreciation, depletion, and amortization 27,135
 11,318
 11,436
 80
 —
 49,969
Depreciation, depletion, and amortization22,059 2,946 10,348 607 35,960 
Impairments 49,443
 —
 —
 —
 —
 49,443
Impairments109,318 0 0 0 0 109,318 
Total expenses 104,288
 30,455
 59,833
 80
 (14,355) 180,301
Total expenses203,731 23,897 37,017 607 (4,871)260,381 
Total operating income (loss)(1)
 (25,434) (4,636) 3,257
 (80) —
  
General and administrative expense —
 —
 —
 (8,852) —
 (8,852)
Gain on disposition of assets —
 151
 —
 3
 —
 154
Gain on derivatives —
 —
 —
 6,969
 —
 6,969
Interest expense, net —
 —
 —
 (10,002) —
 (10,002)
General and administrativeGeneral and administrative0 0 0 25,814 0 25,814 
(Gain) loss on disposition of assets(Gain) loss on disposition of assets(45)(548)(9)1,479 0 877 
Income (loss) from operationsIncome (loss) from operations(176,729)5,853 711 (27,900)0 (198,065)
Loss on derivativesLoss on derivatives0 0 0 (6,937)0 (6,937)
Write-off of debt issuance costsWrite-off of debt issuance costs0 0 0 (2,426)0 (2,426)
Reorganization itemsReorganization items0 0 0 (7,027)0 (7,027)
Interest, netInterest, net0 0 (542)(7,066)0 (7,608)
Other —
 —
 —
 3
 —
 3
Other9 6 22 6 0 43 
Income (loss) before income taxes $(25,434) $(4,485) $3,257
 $(11,959) $—
 $(38,621)Income (loss) before income taxes$(176,720)$5,859 $191 $(51,350)$0 $(222,020)
_______________________
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.

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
 Nine Months Ended September 30, 2017 Oil and Natural GasContract DrillingMid-streamCorporate and OtherEliminationsTotal Consolidated
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands)
 (In thousands)
Revenues:            
Revenues: (1)
Revenues: (1)
Oil and natural gas $256,241
 $—
 $—
 $—
 $—
 $256,241
Oil and natural gas$77,815 $0 $0 $0 $0 $77,815 
Contract drilling —
 137,617
 —
 —
 (9,558) 128,059
Contract drilling0 50,773 0 0 (7,736)43,037 
Gas gathering and processing —
 —
 198,632
 —
 (48,139) 150,493
Gas gathering and processing0 0 54,630 0 (10,336)44,294 
Total revenues 256,241
 137,617
 198,632
 —
 (57,697) 534,793
Total revenues77,815 50,773 54,630 0 (18,072)165,146 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 99,349
 —
 —
 —
 (3,476) 95,873
Oil and natural gas37,519 0 0 0 (1,277)36,242 
Contract drilling —
 99,794
 —
 —
 (8,581) 91,213
Contract drilling0 36,390 0 0 (7,082)29,308 
Gas gathering and processing —
 —
 156,525
 —
 (44,663) 111,862
Gas gathering and processing0 0 41,550 0 (9,059)32,491 
Total operating costs 99,349
 99,794
 156,525
 —
 (56,720) 298,948
Total operating costs37,519 36,390 41,550 0 (17,418)98,041 
Depreciation, depletion, and amortization 71,544
 41,896
 32,547
 5,558
 —
 151,545
Depreciation, depletion, and amortization38,751 13,504 12,102 1,935 0 66,292 
Total expenses 170,893
 141,690
 189,072
 5,558
 (56,720) 450,493
Total expenses76,270 49,894 53,652 1,935 (17,418)164,333 
Total operating income (loss)(1)
 85,348
 (4,073) 9,560
 (5,558) (977)  
General and administrative expense —
 —
 —
 (26,902) —
 (26,902)
General and administrativeGeneral and administrative0 0 0 10,064 0 10,064 
Gain on disposition of assets 176
 106
 58
 813
 —
 1,153
Gain on disposition of assets(60)(296)(66)0 0 (422)
Income (loss) from operationsIncome (loss) from operations1,605 1,175 1,044 (11,999)(654)(8,829)
Gain on derivatives —
 —
 —
 21,019
 —
 21,019
Gain on derivatives0 0 0 7,927 0 7,927 
Interest expense, net —
 —
 —
 (28,807) —
 (28,807)
Interest, netInterest, net0 0 (345)(8,650)0 (8,995)
Other —
 —
 —
 14
 —
 14
Other0 0 0 6 0 6 
Income (loss) before income taxes $85,524
 $(3,967) $9,618
 $(39,421) $(977) $50,777
Income (loss) before income taxes$1,605 $1,175 $699 $(12,716)(654)$(9,891)
_______________________
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.

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
 Nine Months Ended September 30, 2016Oil and Natural GasContract DrillingMid-streamCorporate and OtherEliminationsTotal Consolidated
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated(In thousands)
 (In thousands)
Revenues:            
Revenues: (1)
Revenues: (1)
Oil and natural gas $206,318
 $—
 $—
 $—
 $—
 $206,318
Oil and natural gas$75,481 $0 $0 $0 $(3)$75,478 
Contract drilling —
 88,786
 —
 —
 —
 88,786
Contract drilling0 65,834 0 0 0 65,834 
Gas gathering and processing —
 —
 168,668
 —
 (35,875) 132,793
Gas gathering and processing0 0 80,399 0 (10,328)70,071 
Total revenues 206,318
 88,786
 168,668
 —
 (35,875) 427,897
Total revenues75,481 65,834 80,399 0 (10,331)211,383 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 98,070
 —
 —
 —
 (5,379) 92,691
Oil and natural gas103,769 0 0 0 (1,566)102,203 
Contract drilling —
 66,489
 —
 —
 —
 66,489
Contract drilling0 46,400 0 0 0 46,400 
Gas gathering and processing —
 —
 129,681
 —
 (30,496) 99,185
Gas gathering and processing0 0 58,988 0 (8,765)50,223 
Total operating costs 98,070
 66,489
 129,681
 —
 (35,875) 258,365
Total operating costs103,769 46,400 58,988 0 (10,331)198,826 
Depreciation, depletion, and amortization 89,378
 34,431
 34,410
 218
 —
 158,437
Depreciation, depletion, and amortization58,787 14,691 22,621 1,478 0 97,577 
Impairments 161,563
 —
 —
 —
 —
 161,563
Impairments377,154 410,126 63,962 0 0 851,242 
Total expenses 349,011
 100,920
 164,091
 218
 (35,875) 578,365
Total expenses539,710 471,217 145,571 1,478 (10,331)1,147,645 
Total operating income (loss)(1)
 (142,693) (12,134) 4,577
 (218) —
  
General and administrative expense —
 —
 —
 (25,811) —
 (25,811)
Gain (loss) on disposition of assets (324) 1,467
 (302)—
(18) —
 823
Loss on abandonment of assetsLoss on abandonment of assets17,554 0 0 0 0 17,554 
General and administrativeGeneral and administrative0 0 0 37,367 0 37,367 
(Gain) loss on disposition of assets(Gain) loss on disposition of assets(58)(139)(15)1,479 0 1,267 
Loss from operationsLoss from operations(481,725)(405,244)(65,157)(40,324)0 (992,450)
Loss on derivatives —
 —
 —
 (4,774) —
 (4,774)Loss on derivatives0 0 0 (6,454)0 (6,454)
Interest expense, net —
 —
 —
 (30,225) —
 (30,225)
Write-off of debt issuance costsWrite-off of debt issuance costs0 0 0 (2,426)0 (2,426)
Reorganization itemsReorganization items0 0 0 (7,027)0 (7,027)
Interest, netInterest, net0 0 (1,060)(19,805)0 (20,865)
Other —
 —
 —
 (11) —
 (11)Other30 23 39 11 0 103 
Income (loss) before income taxes $(143,017) $(10,667) $4,275
 $(61,057) $—
 $(210,466)
Loss before income taxesLoss before income taxes$(481,695)$(405,221)$(66,178)$(76,025)$0 $(1,029,119)
_______________________ ____________________ 
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes.
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 GasContract DrillingMid-streamCorporate and OtherEliminationsTotal Consolidated
 (In thousands)
Revenues: (1)
Oil and natural gas$163,910 $0 $0 $0 $0 $163,910 
Contract drilling0 108,972 0 0 (14,780)94,192 
Gas gathering and processing0 0 125,139 0 (28,404)96,735 
Total revenues163,910 108,972 125,139 0 (43,184)354,837 
Expenses:
Operating costs:
Oil and natural gas71,527 0 0 0 (2,571)68,956 
Contract drilling0 73,775 0 0 (13,066)60,709 
Gas gathering and processing0 0 97,679 0 (25,833)71,846 
Total operating costs71,527 73,775 97,679 0 (41,470)201,511 
Depreciation, depletion, and amortization74,518 26,203 23,828 3,869 0 128,418 
Total expenses146,045 99,978 121,507 3,869 (41,470)329,929 
General and administrative0 0 0 19,805 0 19,805 
(Gain) loss on disposition of assets(138)-841,449 (108)(10)0 1,193 
Income (loss) from operations18,003 7,545 3,740 (23,664)(1,714)3,910 
Gain on derivatives0 0 0 995 0 995 
Interest, net0 0 (681)(16,852)0 (17,533)
Other0 0 0 11 0 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.


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Condensed Consolidating Balance Sheets (Unaudited)
June 30, 2020
ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents$13,214 $0 $23,780 $0 $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 supplies0 110 0 0 110 
Income taxes receivable850 0 0 0 850 
Prepaid expenses and other6,575 2,763 7,321 0 16,659 
Total current assets22,341 40,089 51,619 (5,290)108,759 
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties0 6,566,669 0 0 6,566,669 
Unproved properties not being amortized0 30,342 0 0 30,342 
Drilling equipment0 1,296,319 0 0 1,296,319 
Gas gathering and processing equipment0 0 833,402 0 833,402 
Saltwater disposal systems0 43,843 0 0 43,843 
Corporate land and building0 59,080 0 0 59,080 
Transportation equipment362 13,055 3,363 0 16,780 
Other29,005 29,031 0 0 58,036 
29,367 8,038,339 836,765 0 8,904,471 
Less accumulated depreciation, depletion, amortization, and impairment27,888 7,381,777 493,386 0 7,903,051 
Net property and equipment1,479 656,562 343,379 0 1,001,420 
Intercompany receivable853,800 0 0 (853,800)0 
Investments15,106 0 0 (15,106)0 
Right of use asset34 3,303 4,542 (51)7,828 
Other assets6,001 10,316 6,054 0 22,371 
Total assets$898,761 $710,270 $405,594 $(874,247)$1,140,378 

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June 30, 2020
ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable$1,386 $18,018 $9,980 $(2,576)$26,808 
Accrued liabilities14,267 12,876 6,029 (1,788)31,384 
Current operating lease liability18 2,136 2,518 (6)4,666 
Current portion of long-term debt124,000 0 0 0 124,000 
Debtor-in-possession financing8,000 0 0 0 8,000 
Current derivative liability5,011 0 0 0 5,011 
Current portion of other long-term liabilities0 5,615 8,059 (46)13,628 
Total current liabilities152,682 38,645 26,586 (4,416)213,497 
Intercompany debt0 853,491 309 (853,800)0 
Long-term debt0 0 34,000 0 34,000 
Non-current derivative liability145 0 0 0 145 
Operating lease liability16 1,130 1,911 (45)3,012 
Other long-term liabilities6,124 75,499 3,979 (880)84,722 
Liabilities subject to compromise694,512 65,208 0 0 759,720 
Deferred income taxes4,750 0 0 0 4,750 
Total shareholders’ equity40,532 (323,703)338,809 (15,106)40,532 
Total liabilities and shareholders’ equity$898,761 $710,270 $405,594 $(874,247)$1,140,378 

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December 31, 2019
ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents$503 $68 $0 $0 $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 supplies0 449 0 0 449 
Current derivative asset633 0 0 0 633 
Income tax receivable1,756 0 0 0 1,756 
Assets held for sale0 5,908 0 0 5,908 
Prepaid expenses and other2,019 3,373 7,686 0 13,078 
Total current assets7,556 74,603 32,339 (9,447)105,051 
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties0 6,341,582 0 0 6,341,582 
Unproved properties not being amortized0 252,874 0 0 252,874 
Drilling equipment0 1,295,713 0 0 1,295,713 
Gas gathering and processing equipment0 0 824,699 0 824,699 
Saltwater disposal systems0 69,692 0 0 69,692 
Corporate land and building0 59,080 0 0 59,080 
Transportation equipment9,712 16,621 3,390 0 29,723 
Other28,927 29,065 0 0 57,992 
38,639 8,064,627 828,089 0 8,931,355 
Less accumulated depreciation, depletion, amortization, and impairment33,794 6,537,731 407,144 0 6,978,669 
Net property and equipment4,845 1,526,896 420,945 0 1,952,686 
Intercompany receivable1,048,785 0 0 (1,048,785)0 
Investments865,252 0 0 (865,252)0 
Right of use asset46 1,733 3,948 (54)5,673 
Other assets8,107 9,094 9,441 0 26,642 
Total assets$1,934,591 $1,612,326 $466,673 $(1,923,538)$2,090,052 

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December 31, 2019
ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable$12,259 $61,002 $18,511 $(7,291)$84,481 
Accrued liabilities28,003 14,024 6,691 (2,156)46,562 
Current operating lease liability20 1,009 2,407 (6)3,430 
Current portion of long-term debt108,200 0 0 0 108,200 
Current portion of other long-term liabilities3,003 7,313 7,060 0 17,376 
Total current liabilities151,485 83,348 34,669 (9,453)260,049 
Intercompany debt0 1,047,599 1,186 (1,048,785)0 
Long-term debt less debt issuance costs646,716 0 16,500 0 663,216 
Non-current derivative liability27 0 0 0 27 
Operating lease liability25 690 1,404 (48)2,071 
Other long-term liabilities12,553 74,662 8,126 0 95,341 
Deferred income taxes68,150 (54,437)0 0 13,713 
Total shareholders' equity1,055,635 460,464 404,788 (865,252)1,055,635 
Total liabilities and shareholders’ equity$1,934,591 $1,612,326 $466,673 $(1,923,538)$2,090,052 

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Condensed Consolidating Statements of Operations (Unaudited)

Three Months Ended June 30, 2020
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Revenues$0 $56,159 $37,719 $(4,871)$89,007 
Expenses:
Operating costs0 93,305 26,671 (4,873)115,103 
Depreciation, depletion, and amortization607 25,005 10,348 0 35,960 
Impairments0 109,318 0 0 109,318 
General and administrative0 25,814 0 0 25,814 
(Gain) loss on disposition of assets1,479 (593)(9)0 877 
Total operating costs2,086 252,849 37,010 (4,873)287,072 
Income (loss) from operations(2,086)(196,690)709 2 (198,065)
Interest, net(7,066)0 (542)0 (7,608)
Write off of debt issuance costs(2,426)0 0 0 (2,426)
Loss on derivatives(6,937)0 0 0 (6,937)
Reorganization items(2,205)(4,822)0 0 (7,027)
Other, net4 18 21 0 43 
Income (loss) before income taxes(20,716)(201,494)188 2 (222,020)
Income tax benefit(6,455)0 0 0 (6,455)
Equity in net earnings from investment in subsidiaries, net of taxes(201,304)0 0 201,304 0 
Net income (loss)(215,565)(201,494)188 201,306 (215,565)
Less: net income attributable to non-controlling interest84 0 84 (84)84 
Net income (loss) attributable to Unit Corporation$(215,649)$(201,494)$104 $201,390 $(215,649)
Three Months Ended June 30, 2019
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Revenues$0 $128,588 $54,630 $(18,072)$165,146 
Expenses:
Operating costs0 73,909 41,550 (17,418)98,041 
Depreciation, depletion, and amortization1,935 52,255 12,102 0 66,292 
General and administrative0 10,064 0 0 10,064 
Gain on disposition of assets0 (356)(66)0 (422)
Total operating costs1,935 135,872 53,586 (17,418)173,975 
Income (loss) from operations(1,935)(7,284)1,044 (654)(8,829)
Interest, net(8,650)0 (345)0 (8,995)
Gain on derivatives7,927 0 0 0 7,927 
Other, net6 0 0 0 6 
Income (loss) before income taxes(2,652)(7,284)699 (654)(9,891)
Income tax benefit(848)(1,026)0 0 (1,874)
Equity in net earnings from investment in subsidiaries, net of taxes(6,705)0 0 6,705 0 
Net income (loss)(8,509)(6,258)699 6,051 (8,017)
Less: net income attributable to non-controlling interest0 0 492 0 492 
Net income (loss) attributable to Unit Corporation$(8,509)$(6,258)$207 $6,051 $(8,509)

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Six Months Ended June 30, 2020
ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands)
Revenues$0 $141,315 $80,399 $(10,331)$211,383 
Expenses:
Operating costs0 150,169 58,988 (10,331)198,826 
Depreciation, depletion, and amortization1,478 73,478 22,621 0 97,577 
Impairments0 787,280 63,962 0 851,242 
Loss on abandonment of assets0 17,554 0 0 17,554 
General and administrative0 37,367 0 0 37,367 
(Gain) loss on disposition of assets1,479 (197)(15)0 1,267 
Total operating costs2,957 1,065,651 145,556 (10,331)1,203,833 
Loss from operations(2,957)(924,336)(65,157)0 (992,450)
Interest, net(19,805)0 (1,060)0 (20,865)
Write-off of debt issuance costs(2,426)0 0 0 (2,426)
Loss on derivatives(6,454)0 0 0 (6,454)
Reorganization items(2,205)(4,822)0 0 (7,027)
Other, net11 53 39 0 103 
Loss before income taxes(33,836)(929,105)(66,178)0 (1,029,119)
Income tax benefit(9,880)0 0 0 (9,880)
Equity in net earnings from investment in subsidiaries, net of taxes(995,283)0 0 995,283 — 
Net loss(1,019,239)(929,105)(66,178)995,283 (1,019,239)
Less: net loss attributable to non-controlling interest(33,096)0 (33,096)33,096 (33,096)
Net loss attributable to Unit Corporation$(986,143)$(929,105)$(33,082)$962,187 $(986,143)

Six Months Ended June 30, 2019
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Revenues$0 $272,882 $125,139 $(43,184)$354,837 
Expenses:
Operating costs0 145,302 97,679 (41,470)201,511 
Depreciation, depletion, and amortization3,869 100,721 23,828 0 128,418 
General and administrative0 19,805 0 0 19,805 
(Gain) loss on disposition of assets(10)1,311 (108)0 1,193 
Total operating costs3,859 267,139 121,399 (41,470)350,927 
Income (loss) from operations(3,859)5,743 3,740 (1,714)3,910 
Interest, net(16,852)0 (681)0 (17,533)
Gain on derivatives995 0 0 0 995 
Other, net11 0 0 0 11 
Income (loss) before income taxes(19,705)5,743 3,059 (1,714)(12,617)
Income tax expense (benefit)(4,547)2,229 0 0 (2,318)
Equity in net earnings from investment in subsidiaries, net of taxes3,145 0 0 (3,145)0 
Net income (loss)(12,013)3,514 3,059 (4,859)(10,299)
Less: net income attributable to non-controlling interest0 0 1,714 0 1,714 
Net income (loss) attributable to Unit Corporation$(12,013)$3,514 $1,345 $(4,859)$(12,013)

                            

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Condensed Consolidating Statements of Comprehensive Income (Loss) (Unaudited)
Three Months Ended June 30, 2020
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal 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 $00 0 0 0 0 
Comprehensive income (loss)(215,565)(201,494)188 201,306 (215,565)
Less: Comprehensive income attributable to non-controlling interests84 0 84 (84)84 
Comprehensive income (loss) attributable to Unit Corporation$(215,649)$(201,494)$104 $201,390 $(215,649)

Three Months Ended June 30, 2019
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal 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 ($9)0(30)0 0 (30)
Comprehensive income (loss)(8,509)(6,288)699 6,051 (8,047)
Less: Comprehensive income attributable to non-controlling interests0 0 492 0 492 
Comprehensive income (loss) attributable to Unit Corporation$(8,509)$(6,288)$207 $6,051 $(8,539)

Six Months Ended June 30, 2020
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal 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 $00 0 0 0 0 
Comprehensive loss(1,019,239)(929,105)(66,178)995,283 (1,019,239)
Less: Comprehensive loss attributable to non-controlling interests(33,096)0 (33,096)33,096 (33,096)
Comprehensive loss attributable to Unit Corporation$(986,143)$(929,105)$(33,082)$962,187 $(986,143)
Six Months Ended June 30, 2019
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Net income (loss)$(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 ($2)0 (6)0 0 (6)
Comprehensive income (loss)(12,013)3,508 3,059 (4,859)(10,305)
Less: Comprehensive income attributable to non-controlling interests0 0 1,714 0 1,714 
Comprehensive income (loss) attributable to Unit Corporation$(12,013)$3,508 $1,345 $(4,859)$(12,019)

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Condensed Consolidating Statements of Cash Flows (Unaudited)
Six Months Ended June 30, 2020
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal 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)0 (23,804)
Producing properties and other acquisitions0 (210)0 0 (210)
Proceeds from disposition of assets1,169 3,253 75 0 4,497 
Net cash provided by (used in) investing activities409 (10,385)(9,541)0 (19,517)
FINANCING ACTIVITIES:
Borrowings under credit agreement, including borrowings under DIP credit facility47,300 0 32,100 0 79,400 
Payments under credit agreement(23,500)0 (14,600)0 (38,100)
DIP financing costs(990)0 0 0 (990)
Intercompany borrowings (advances), net198,503 (49,169)(771)(148,563)0 
Payments on finance leases0 0 (2,061)0 (2,061)
Employee taxes paid by withholding shares(43)0 0 0 (43)
Bank overdrafts(7,269)0 (1,464)0 (8,733)
Net cash provided by (used in) financing activities214,001 (49,169)13,204 (148,563)29,473 
Net increase (decrease) in cash and cash equivalents12,711 (68)23,780 0 36,423 
Cash and cash equivalents, beginning of period503 68 0 0 571 
Cash and cash equivalents, end of period$13,214 $0 $23,780 $0 $36,994 

Six Months Ended June 30, 2019
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal 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)0 (246,638)
Producing properties and other acquisitions0 (3,313)0 0 (3,313)
Proceeds from disposition of assets10 7,247 83 0 7,340 
Net cash used in investing activities(90)(209,048)(33,473)0 (242,611)
FINANCING ACTIVITIES:
Borrowings under credit agreement238,800 0 32,400 0 271,200 
Payments under credit agreement(135,300)0 (24,900)0 (160,200)
Intercompany borrowings (advances), net(96,311)97,384 (1,107)34 0 
Payments on finance leases0 0 (1,980)0 (1,980)
Employee taxes paid by withholding shares(4,073)0 0 0 (4,073)
Distributions to non-controlling interest919 0 (1,837)0 (918)
Bank overdrafts4,183 0 1,115 0 5,298 
Net cash provided by financing activities8,218 97,384 3,691 34 109,327 
Net increase (decrease) in cash and cash equivalents105 (49)(5,839)0 (5,783)
Cash and cash equivalents, beginning of period403 208 5,841 0 6,452 
Cash and cash equivalents, end of period$508 $159 $2 $0 $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 the followingthese 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 as well asand 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.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.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 our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our oilown 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 natural gas segment.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, as well as,and the demand for our drilling rigs which in turn, influences the amounts we can charge for those drilling rigs. While our operations are locatedall within the United States, events outside the United States affect us and our industry.


Deteriorating commodityThe 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 worldwide duringand ensuing reductions of exploration and production company capital and operating budgets. On April 12, 2020, the past several years brought about significantOrganization of the Petroleum Exporting Countries (OPEC), Russia and adverse changescertain other oil producing states (commonly referred to our industryas OPEC Plus) agreed to cut oil production by 9.7 million barrels per day in May and us. As a result we reduced or stopped, for a periodJune 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 time, ourthe 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 segment's drilling activity. Industry wide reductions in drilling activitysupply and spending for extended periods also tendsdemand imbalance persists and continues to reducehave a significant adverse effect on the rates foroil and gas industry.

During the number of ourlast three years, commodity prices have been volatile. Our oil and natural gas segment used two to three drilling rigs that we can work. In addition, sustained lowerthroughout 2017. With improved commodity prices impactduring the liquidity condition of some of our industry partners and customers, which, in turn, could limit their ability to meet their financial obligations to us.

During 2016, commodity prices began to improve. In the fourthfirst quarter of 2016,2018, our oil and natural gas segment began using twoput four of our drilling rigs to work and has been using twoincreased the number to three of themsix drilling rigs for a brief period during the first nine monthsthird quarter of 2017. Our contract drilling segment completed the construction and contracted the ninth and tenth BOSS drilling rigs2018. We reduced our operated rig count in the fourth quarter of 20162018 and the first quarter of 2019 before getting as high as six drilling rigs again in the second quarter of 2017, respectively. Our2019. Due to declining prices we shut down our drilling rig segment's rig utilization increased from 16program in July 2019 and used no drilling rigs working asthe 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:

unt-20200630_g2.jpg
The following chart reflects the significant fluctuations in the prices for NGLs:

unt-20200630_g3.jpg
_________________________
1.NGLs prices reflect a weighted-average, based on production, of Mont Belvieu and Conway prices.

For the six months ended June 30, 2016,2020, 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 33 drilling rigs working asdrill wells pending our ability to refinance our debt and the outcome of September 30, 2017. The extent and durationthe Restructuring.

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Table of this improvement remains uncertain.Contents


The reduction inIn the first six months of 2020, we incurred a non-cash ceiling test write-down of our oil NGLs, and natural gas prices had a numberproperties of consequences for us (although, as noted, we are starting to see some improvements). Below are some of those consequences:

We incurred non-cash ceiling test write-downs in the first nine months of 2016 of $161.6$377.2 million pre-tax ($100.6330.1 million net of tax). We did not have a write-down in the fourth quarter of 2016 or the first three quarters of 2017. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at September 30, 2017, and only adjustWe 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 priceprices as of August 2020. We will be required to an estimated fourth quarter ending average (holding October 2017 prices constant for the remaining two monthsadopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fourthfresh start reporting date, and those values may materially change relative to our historical consolidated financial statements.

During the first quarter of 2017),2020, in addition to the impairment evaluations of our forward looking expectation isproved 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 willconsider 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 recognizehave 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 fourthsecond quarter of 2017. But commodity prices (and other factors) remain volatile2020.

Within our mid-stream segment, we determined that the carrying value of certain long-lived asset groups in southern Kansas, and they could negativelycentral Oklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. Based on the 12-month average price resultingestimated 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 the potential forour Consolidated Statement of Operations. We did not have an impairment in the future.
We reduced the number of gross wells our oil and natural gas segment drilled in 2016 by approximately 64% from the number drilled in 2015 due to our reduced cash flow. For 2017, we plan to increase the number of gross wells drilled to 60 - 65 wells (depending on future commodity prices).
The decline in drilling by our customers reduced the average utilization of our drilling rig fleet. At December 31, 2015, we had 26 drilling rigs operating. In 2016, utilization continued downward bottoming out in May 2016 at 13 operating drilling rigs. After May commodity prices began improving for the remainder of the year and we exited 2016 with 21 active rigs. As of September 30, 2017, we had 33 drilling rigs operating (an improvement of 57% over the end of the year). Operators have been increasing drilling, but the extent of further increases remain uncertain. During the second quarter of 2017, we completed the construction of our tenth BOSS drilling rig and all of our BOSS drilling rigs are under contract.2020.
Due to low ethane price, we continue to operate some of our mid-stream processing facilities in ethane rejection mode which reduces the amount of liquids sold.  As long as ethane price relative to natural gas price remains depressed, we expect to continue operating in ethane rejection mode at some of our processing facilities.
Also, as noted elsewhere, beginning on April 4, 2017, we began an at-the-market offering for the sale of shares of our common stock. The offering allows us to sell shares, from time to time, up to an aggregate of $100 million in gross proceeds. As of September 30, 2017, we sold 787,547 shares for $18.6 million, net of offering costs of $0.4 million. Approximately $81.0 million remain available for sale under the program. Net proceeds from the offering will be used to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.

On April 3, 2017, we closed an acquisition of certain oil and natural gas assets from an unrelated third party. The acquisition includes approximately 47 proved developed producing wells and 8,300 net acres primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million. The effective date of this acquisition was January 1, 2017.

Executive Summary


Oil and Natural Gas


ThirdSecond quarter2017 2020 production from our oil and natural gas segment was 4,057,0003,004,000 barrels of oil equivalent (Boe), an increasea decrease of 5% over13% from the first quarter of 2020 and a decrease of 28% from the second quarter of 2017 and a decrease of 3%2019. The decreases came from the third quarter of 2016, respectively. The increase over the second quarter of 2017 was from acquiredfewer net wells and new wells drilledbeing completed in the firstlast nine months of 2017. The decrease from the thirdto replace declines in existing drilled wells.

Second quarter of 2016 was primarily due to the continued production decline of existing wells and reduced drilling activity between the periods. During the quarter, plant outages and delays attributable to hurricane Harvey reduced quarterly production by approximately 100 MBoe. The effects of Harvey were principally due to NGL bottlenecks from fractionation plant partial shut-downs and operational delays on new wells and recompletions. After the end of the quarter, the third-party processing plant for the majority of Unit’s natural gas production in the Gulf Coast area went down due to an equipment failure. The plant was down seven days before operations resumed. Cumulatively, hurricane Harvey, the Texas Panhandle ice storm in the first quarter, and third party plant downtimes will reduce production for the year by approximately 460 MBoe. 

Third quarter 20172020 oil and natural gas revenues increased 3% overdecreased 44% from the first quarter of 2020 and decreased 65% from the second quarter of 2017 and increased 8% over the third quarter of 2016.2019. The increase over the second quarter of 2017 was duedecreases were primarily to higher oil and NGLfrom a decrease in commodity prices and higherproduction.

production volumes partially offset by lower natural gas prices. The increase over the third quarter of 2016 was due primarily to higher commodity prices partially offset by lower production volumes.


Our oil prices for the thirdsecond quarter of 2017 increased 1% over2020 decreased 53% from the first quarter of 2020 and decreased 65% from the second quarter of 2017 and increased 11% over the third quarter of 2016.2019. Our NGLs prices increased 23%26% over the first quarter of 2020 and decreased 67% from the second quarter of 2017 and increased 45% over the third quarter of 2016.2019. Our natural gas prices decreased 4%12% from the first quarter of 2020 and decreased 42% from the second quarter of 2017 and increased 3% over the third quarter of 2016.2019.


Operating cost per Boe produced for the thirdsecond quarter of 2017 decreased 2% from2020 increased 167% over the first quarter of 2020 and increased 173% over the second quarter of 2017 and increased 35% over the third quarter of 2016.2019. The decrease from the second quarter of 2017 wasincreases were primarily due to higher production volumes partially offset by higher lease operating expenses and higher production taxes. The increase over the third quarter of 2016 was primarily due to lower production volumes, increased lease operating expenses, and higher production taxesa $45.0 million estimated litigation settlement partially offset by lower salt water disposal expense.production applied against fixed costs and no G&G cost capitalized in the first half of 2020.


At SeptemberJune 30, 2017, we had2020, these derivatives were outstanding:
TermCommodityContracted Volume
Weighted Average 

Fixed Price
Contracted Market
Oct'17Jul'20 - Dec'20Natural gas –- basis swap70,00030,000 MMBtu/day$3.038(0.275)IF – NYMEX (HH)NGPL TEXOK
Nov’17 – Dec'17Jul'20 - Dec'20Natural gas –- basis swap60,00020,000 MMBtu/day$2.960(0.455)IF – NYMEX (HH)PEPL
Jan’18 – Dec'18Jan'21 - Dec'21Natural gas –- basis swap20,00030,000 MMBtu/day$3.013(0.215)IF – NYMEX (HH)NGPL TEXOK
Nov’17 – Dec'17Jul'20 - Dec'20Natural gas – basis swap20,000 MMBtu/day$(0.215)IF – NYMEX (HH)
Jan’18 – Mar'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Nov’18 – Dec'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Oct'17Natural gas – collar20,000 MMBtu/day$2.88 - $3.10IF – NYMEX (HH)
Oct'17Natural gas – three-way collar15,00030,000 MMBtu/day$2.50 - $2.00$2.20 - $3.32$2.80IF –- NYMEX (HH)
Nov’17 – Dec'17Jul'20 - Sep'20Natural gas – three-way collar25,000 MMBtu/day$2.90 - $2.30 - $3.59IF – NYMEX (HH)
Jan'18 – Mar'18Natural gas – three-way collar60,000 MMBtu/day$3.29 - $2.63 - $4.07IF – NYMEX (HH)
Apr'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Oct’17 – Dec'17Crude oil – three-way- collar3,750112,000 Bbl/daymonth$49.7920.00 - $39.58$26.50WTI - $60.98WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar2,000 Bbl/day$47.50 - $37.50 - $56.08WTI – NYMEX
Jan'18 – Dec'18Crude oil – swap2,000 Bbl/day$50.140WTI – NYMEX

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After SeptemberJune 30, 2017, the following derivative was2020, these derivatives were entered into:
TermCommodityContracted Volume
Weighted Average
Fixed Price
Contracted Market
Apr'18 – Oct'18Sep'20 - Dec'20Natural gas –- swap10,000 MMBtu/day$2.9902.72IF –- NYMEX (HH)
Apr'18 – Sep'18Sep'20 - Oct'21
Liquids –Natural gas - swap(1)
1,00020,000 MMBtu/day$2.77IF - NYMEX (HH)
Jan'21 - Oct'21Natural gas - swap30,000 MMBtu/day$2.85IF - NYMEX (HH)
Nov'21 - Dec'21Natural gas - swap45,000 MMBtu/day$2.90IF - NYMEX (HH)
Jan'22 - Dec'22Natural gas - collar35,000 MMBtu/day$2.50 - $2.68IF - NYMEX (HH)
Oct'20 - Dec'20Crude oil - swap4,000 Bbl/day$31.16443.35OPIS – Mont BelvieuWTI - NYMEX
Jan'21 - Dec'21Crude oil - swap3,000 Bbl/day$44.65WTI - NYMEX
_______________________

(1)    TypeAfter 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 liquid involvedthe commencement of the Chapter 11 Cases, our ability to enter into derivative transactions is propane.limited.


For the ninesix months ended SeptemberJune 30, 2017,2020, we completed drilling 43participated in the completion of 27 gross wells (15.10(6.16 net wells). drilled by other operators. For all of 2017,2020, we plando not currently have any plans to participate in the drilling of approximately 60drill wells pending our ability to 65 gross wells.Excluding acquisitions and ARO liability,refinance our estimated 2017 capital expenditures for this segment are approximately $216.0 million. Our current 2017 production guidance is approximately 16.0 MMBoe, a decrease of 7% from 2016, although actual results continue to be subject to many factors.debt.


Contract Drilling


The average number of drilling rigs we operated in the thirdsecond quarter of 20172020 was 34.69.1 compared to 28.818.7 and 16.028.6 in the first quarter of 2020 and the second quarter of 2017 and the third quarter of 2016,2019, respectively. As of SeptemberJune 30, 2017, 332020, five of our drilling rigs were operating.


Revenue for the thirdsecond quarter of 2017 increased 31%2020 decreased 20% from the first quarter of 2020 and 100% overdecreased 32% from the second quarter of 2017 and the third quarter of 2016, respectively.2019. The increase overdecreases were primarily due to less drilling rigs operating.

Dayrates for the second quarter of 2017 was primarily due to an increase in drilling rigs operating and

dayrates. The increase over the third quarter of 2016 was primarily due to increased utilization partially offset by lower dayrates.

Dayrates for the third quarter of 20172020 averaged $16,454, a 3% increase over the second quarter of 2017 and$18,340, a 6% decrease from the thirdfirst quarter of 2016. The increase over2020 and an 1% decrease from the second quarter of 2017 was2019. The decreases were both primarily due to a labor increase that was passed through to contracted rigs. The decrease from the third quarter of 2016 was primarily due to downward pressure on dayrates due to lower demand as higher rate contracts were expiring.less drilling rigs operating.


Operating costs for the thirdsecond quarter of 2017 increased 28% over2020 decreased 18% from the first quarter of 2020 and decreased 29% from the second quarter of 2017 and increased 82% over the third quarter of 2016.2019. The increasesdecreases were both primarily due primarily to moreless drilling rigs operating.

Almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The improved commodity pricing for oil and natural gas that began during the second half of 2016 has increased demand for drilling rigs. Our drilling rig count bottomed out at 13 drilling rigs operating during the second quarter of 2016, but increased to 21 drilling rigs operating at the end of 2016. Our drilling rig count continued to increase during the first three quarters of 2017 to 36 drilling rigs during the third quarter but we ended the third quarter with 33 operating drilling rigs. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates.


We have ninethree term drilling contracts with original terms ranging from six months to two years. Fouryears that are up for renewal in the fourth quarter of 2017, three in the first quarter of 2018, one in the second quarter of 2018, and one in 2019.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 withwho 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 first nine monthssecond quarter of 2017,2020, we recorded $0.8$9.2 million ofin early termination fees. We recorded $4.8 million in early termination fees compared to $3.1 million in the first ninesix months of 2016.2019.

All tenFour of our 14 existing BOSS drilling rigs are under contract. Three stacked Mid-Continent SCR drilling rigs were returned to service in the third quarter. One was relocated from our Rocky Mountain division. Three SCR rigs also completed their contracts during the quarter. Our estimated 2017

For 2020, we do not currently have an approved capital expendituresplan for this segment are approximately $38.0 million.segment. Capital expenditures incurred would be within anticipated cash flows.

Competition to keep qualified labor continues to be an issue we face in this segment. We do not believe this shortage of qualified labor will keep us from working additional drilling rigs, but it could cause some delays in the time to crew new drilling rigs. Beginning in third quarter 2017, we increased compensation for certain drilling rig personnel.


Mid-Stream


ThirdSecond quarter 20172020 liquids sold per day increased 1%21% over the first quarter of 2020 and decreased 10% from the second quarter of 2017 and decreased 5% from the third quarter of 2016, respectively.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 20172019 was due to increasedlower purchased volumes available to our processing facilities. The decreasefrom fewer well connects. For the second quarter of 2020, gas processed per day decreased 7% from the thirdfirst quarter of 2016 was2020 and decreased 6% from the second quarter of 2019. The decreases were primarily due to less volume available to process atlower volumes from fewer new well connects on our plants.processing systems. For the thirdsecond quarter of 2017,2020, gas processedgathered per day increased 4% over the secondfirst quarter of 20172020 and decreased 8% from the third quarter of 2016. The increase over the second quarter of 2017 was primarily due to higher processed volumes from new wells at our Cashion facility and our Hemphill facility. The decrease from the third quarter of 2016 was primarily due to declines in existing volumes, fewer new wells connected, and no offload volume at our Hemphill facility in 2017. For the third quarter of 2017, gas gathered per day was essentially unchanged and decreased 11%13% from the second quarter of 2017 and2019, respectively. The increase over the thirdfirst quarter of 2016, respectively. The2020 was due to adding new infill wells on one of our gathering systems in the Appalachian region, while the decrease from the thirdsecond quarter of 20162019 was primarily due to declining gathered volume onvolumes from most of our major systems in both the Appalachian gathering systems.region and the mid-continent area.

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NGLs prices in the thirdsecond quarter of 2017 increased 27% over2020 decreased 20% from the prices received in the first quarter of 2020 and decreased 38% from the prices received in the second quarter of 2017 and increased 53% over the prices received in the third quarter of 2016.2019. Because certain of the contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts–contracts, under which we receive a share of the proceeds from the sale of the NGLs–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 thirdsecond quarter of 2017 increased 6% over2020 decreased 18% from the first quarter of 2020 and decreased 30% from the second quarter of 2017 and increased 7% over2019. The decreases were both primarily due to lower purchase prices, along with less purchased volumes.

At the third quarter of 2016. Third quarter of 2017 costs were higher thanCashion processing facility in central Oklahoma, total throughput volume for the second quarter of 2017 primarily due2020 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 both increased purchase volumes and prices and increased field directconnect 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 expenses.cost savings. The increase overtotal processing capacity on the third quarter of 2016 was primarily due to higher gas purchase prices and higher field direct operating expenses partialy offset by lower purchase volumes.Cashion system is 105 MMcf per day.


In the Appalachian region ourat the Pittsburgh Mills gathering system, in Allegheny and Butler counties, continues to produce consistent financial results. Our average gathered volume for the thirdsecond quarter of 2017 is approximately 128.52020 was 181.8 MMcf per day.

We connectedday while the average gathered volume for June 2020 was approximately 169.3 MMcf per day as the new AllenBakerstown wells started to decline. During the second quarter of 2020, we added one new infill well padto this system. This was the fourth and final well added to the Bakerstown pad.

At the Hemphill processing facility located in Maythe Texas panhandle, average total throughput volume for the second quarter of 2020 was 52.4 MMcf per day and it included five new wells.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 in the third quarter. We are constructing a pipeline to connect the Miller well pad, which will be the next pad connected to our system. The Miller pad will include seven new wells and we anticipate it will be ready to flow in the third quarter of 2018. Also, we anticipate several in-fill wells to be drilled and connected to ourthis system in the second halfquarter of 2018.2020. 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 our Hemphillthe Segno gathering system located in East Texas, system, our totalthe average throughput volume averaged 60.8for the second quarter of 2020 decreased to 42.4 MMcf per day fordue to declining production volume along with no new drilling activity in the thirdarea. During the second quarter of 2017 and our total production of natural gas liquids was approximately 164,000 gallons per day. During the third quarter,2020, we connected two new wells and since the beginning of 2017, we connected fourdid not connect any new wells to this processing facility. Our oil and gas segment continues to operate a rig and wesystem. We do not anticipate connecting two more wells in the fourth quarter.  

At our Cashion processing facility in central Oklahoma, our total throughput volume for the third quarter of 2017 averaged approximately 38.4 MMcf per day and our total production of natural gas liquids was approximately 196,000 gallons per day. Total processing capacity for this facility remains at approximately 45 MMcf per day. We connected fourany new wells to this system in the third quarter for a total of six new2020 but UPC will continue to perform some workovers in addition to some recompletions on existing wells connected in 2017. We completed a construction project that allows us to bring additional gas to this processing plant from a third party producer. This new producer will deliver fee-based volume to us for five years or will pay a shortfall fee settled annually. We are in the process of constructing a new pipeline extension which will allow us to connect a new producer to our system. We have connected one well from this producer and plan to connect two more wells in the fourth quarter.


At our Bellmon processing facility in the Mississippian play in north central Oklahoma, we connected two new wells in the third quarter of 2017 and since the beginning of 2017, we connected nine new wells to this processing facility. Our total throughput volume averaged approximately 27.5 MMcf per day. Total natural gas liquids averaged approximately 131,000 gallons per day while operating in ethane recovery mode at this facility. Total processing capacity at this system is approximately 90 MMcf per day.

At our Segno gathering facility in Southeast Texas, gathered volume for the third quarter of 2017 averaged approximately 81.5 MMcf per day. At this facility, we have increased our gathering and dehydration capacity to approximately 120 MMcf per day. We have connected two new wells to this system in 2017.

Our estimated 2017Anticipated 2020 capital expenditures for this segment arewill be approximately $18.9 million.$10.8 million, an 83% decrease from 2019.


Financial Condition and Liquidity


Summary


Our financial condition and liquidity dependsdepend on the cash flow from our operations and borrowings under our credit agreement.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.


We believe we will have enough cash flowThe significant risks and uncertainties related to the company’s liquidity has caused the company to meet our obligations and remain in compliance with our debt covenantsconclude 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 next twelve months. Our ability to meet our debt covenants (under our credit agreement and our 2011 Indenture) and our capacity to incur additional indebtedness will depend on our future performance, which will be affected by financial, business, economic, regulatory, and other factors. For example, if we experience lower oil, natural gas, and NGLs prices since the last borrowing base determination under our credit agreement, it could cause a reduction of the borrowing base and therefore reduce or limit our ability to incur indebtedness. We monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues, and work, where possible, with our lenders to address those issues ahead of time.periods indicated:

 Six Months Ended June 30,%
Change
 20202019
 (In thousands except percentages)
Net cash provided by operating activities26,467 127,501 (79)%
Net cash used in investing activities(19,517)(242,611)92 %
Net cash provided by financing activities29,473 109,327 (73)%
Net increase (decrease) in cash and cash equivalents$36,423 $(5,783)

  Nine Months Ended September 30, 
%
Change
  2017 2016 
  (In thousands except percentages)
Net cash provided by operating activities $184,792
 $197,762
 (7)%
Net cash used in investing activities (204,184) (107,509) 90 %
Net cash provided by (used in) financing activities 19,321
 (90,175) 121 %
Net increase (decrease) in cash and cash equivalents $(71) $78
  


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 impactedaffected by changes in working capital.


Net cash provided by operating activities in the first ninesix months of 20172020 decreased by $13.0$101.0 million as compared to the first ninesix months of 2016.2019. The decrease was the result ofprimarily 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 partially offset by higher profit margins in all three segments.disbursements.


Cash Flows from Investing Activities


We dedicate and expect to continue to dedicate a substantial portion of our capital budget to the exploration for and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells.

Cash flows used in investing activities increaseddecreased by $96.7$223.1 million for the first ninesix months of 20172020 compared to the first ninesix months of 2016.2019. The change was due primarily to an increasea decrease in capital expenditures due to andecreases in wells drilled and oil and gas property acquisition, the restarting of our drilling program in 2017, the construction of two new BOSS drilling rigs, andacquisitions partially offset by a decrease in the proceeds received from the disposition of assets. SeeFor additional information on capital expenditures, see below under Capital Requirements.


Cash Flows from Financing Activities


Cash flows provided by financing activities increaseddecreased by $109.5$79.9 million for the first ninesix months of 20172020 compared to the first ninesix months of 2016.2019. The increasedecrease was primarily due to proceeds froma decrease in the ATM common stock programnet borrowings under our credit agreements and an increasea decrease in book overdrafts in 2017 coupled with almost no change in net borrowing after paying down long-term debt in 2016.bank overdrafts.


At SeptemberJune 30, 2017,2020, we had unrestricted cash and cash equivalents totaling $0.8$37.0 million and had borrowed $162.1$124.0 million, $8.0 million, and $34.0 million of the $475.0 million we had elected to then haveamounts available under ourthe Unit, DIP, and Superior credit agreement. Our credit agreement is used primarily for working capital and capital expenditures.agreements, respectively.


The following is a summary ofBelow, we summarize certain financial information as of SeptemberJune 30, 20172020 and 20162019 and for the ninesix months ended SeptemberJune 30, 20172020 and 2016:2019:

 June 30,
%
Change (2)
 20202019
 (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
_________________________
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.

59
  September 30, 
%
Change
  2017 2016 
  (In thousands except percentages)
Working capital $(62,181) $(42,342) (47)%
Long-term debt less debt issuance costs $803,833
 $854,583
 (6)%
Shareholders’ equity $1,251,905
 $1,189,576
 5 %
Net income (loss) $28,693
 $(137,307) 121 %
Table of Contents


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 $62.2$104.7 million and $42.3$64.1 million as of SeptemberJune 30, 20172020 and 2016,2019, respectively. The increasedecrease in negative working capital is primarily due to increasedthe springing maturity of the Unit credit agreement and the determination to treat the borrowings as current liabilities and a decrease in accounts payablereceivable due to increased activity in our drilling program and increased drilling rig utilization and the reclassification of current deferred tax asset to long-term asset per ASU 2015-17lower revenues partially offset by increasedreduction in accounts receivable from increased revenuespayable and the changean increase in the value of outstanding derivatives. Ourcash 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.expenditures and the DIP credit facility is used to fund the operation of the Debtors and the Chapter 11 Cases. At SeptemberJune 30, 2017,2020, we had borrowed $162.1$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 $475.0 million available under our credit agreement.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 $0.4$8.5 million as of SeptemberJune 30, 2017 and decreased working capital by $5.6 million as of September 30, 2016.2019.


The followingThis table summarizes certain operating information:
Six Months Ended
 June 30,%
Change
 20202019
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 period13.9 30.0 (54)%
Total drilling rigs available for service at the end of the period58 57 2 %
Average dayrate$19,165 $18,412 4 %
Mid-Stream:
Gas gathered—Mcf/day397,037 457,859 (13)%
Gas processed—Mcf/day160,943 163,725 (2)%
Gas liquids sold—gallons/day582,546 681,070 (14)%
Number of natural gas gathering systems18 21 (14)%
Number of processing plants11 12 (8)%
  Nine Months Ended  
  September 30, 
%
Change
  2017 2016 
Oil and Natural Gas:      
Oil production (MBbls) 1,990
 2,260
 (12)%
NGLs production (MBbls) 3,476
 3,745
 (7)%
Natural gas production (MMcf) 37,317
 42,376
 (12)%
Average oil price per barrel received $47.62
 $38.71
 23 %
Average oil price per barrel received excluding derivatives $46.99
 $36.88
 27 %
Average NGLs price per barrel received $17.05
 $10.16
 68 %
Average NGLs price per barrel received excluding derivatives $17.05
 $10.16
 68 %
Average natural gas price per Mcf received $2.50
 $1.98
 26 %
Average natural gas price per Mcf received excluding derivatives $2.55
 $1.80
 42 %
Contract Drilling:      
Average number of our drilling rigs in use during the period 29.7
 16.7
 78 %
Total number of drilling rigs owned at the end of the period 95
 94
 1 %
Average dayrate $16,120
 $18,147
 (11)%
Mid-Stream:      
Gas gathered—Mcf/day 385,846
 417,722
 (8)%
Gas processed—Mcf/day 133,986
 160,411
 (16)%
Gas liquids sold—gallons/day 518,054
 536,911
 (4)%
Number of natural gas gathering systems 25
 26
 (4)%
Number of processing plants 13
 14
 (7)%


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 ninesix months of 20172020 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 $398,000$662,000 per month ($4.87.9 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 ninesix months of 20172020 was $2.50$1.16 compared to $1.98$2.18 for the first ninesix months of 2016.2019. Based on our first ninesix months of 20172020 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $212,000
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$387,000 per month ($2.54.6 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 $372,000$560,000 per month ($4.56.7 million annualized) change in our pre-

taxpre-tax operating cash flow. In the first ninesix months of 2017,2020, our average oil price per barrel received, including the effect of derivatives, was $47.62$32.93 compared with an average oil price, including the effect of derivatives, of $38.71$58.16 in the first ninesix months of 20162019 and our first ninesix months of 20172020 average NGLs price per barrel received, including the effect of derivatives was $17.05$3.67 compared with an average NGLs price per barrel of $10.16$14.11 in the first ninesix months of 2016.2019.


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 SeptemberJune 30, 2017,2020, the 12-month average unescalated prices were $49.81$47.17 per barrel of oil, $27.70$18.07 per barrel of NGLs, and $3.00$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 did not haverecorded expense of $17.6 million related to take athe write down of our salt water disposal asset in the first nine monthsquarter of 2017.2020.


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. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at September 30, 2017, and only adjustWe 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 priceprices as of August 2020. We will be required to an estimated fourth quarter ending average (holding October 2017 prices constant for the remaining two monthsadopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fourth quarter of 2017),fresh start reporting date, and those values may materially change relative to our forward looking expectation is that we will not recognize an impairment in the fourth quarter of 2017. But commodity prices (and other factors) remain volatile and they could negatively affect the 12-month average price resulting in the potential for an impairment in the future.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 monthsix-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 wereare drilling horizontal or directional wells for oil and NGLs. The improvedcontinuous fluctuations in commodity pricingprices for oil and natural gas that began duringchanges the second half of 2016 has increased demand for drilling rigs. These factors ultimately affect the demand and mix of the type of 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 ninesix months of 2017,2020, our average dayrate was $16,120$19,165 per day compared to $18,147$18,412 per day for the first ninesix months of 2016.2019. The average number of our drilling rigs used in the first ninesix months of 20172020 was 29.713.9 drilling rigs compared with 16.730.0 drilling rigs in the first ninesix months of 2016.2019. Based on the average utilization of our drilling rigs during the first ninesix months of 2017,2020, a $100 per day change in dayrates has a $2,970$1,390 per day ($1.10.5 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 to be associated with acquiring an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in our statement of operations,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 $9.6$14.8 million for the first ninesix months of 20172019, from our contract drilling segment and eliminated the associated operating expense of $8.6$13.1 million during the first six months of 2019, yielding $1.0$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 ninesix months of 2016.2020.


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, 1311 processing plants, 2518 gathering systems, and approximately 1,4802,085 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 ninesix months of 20172020 and 2016,2019, our mid-stream operations purchased $43.2$8.1 million and $28.5$24.8 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $4.9$2.2 million and $7.4$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 385,846397,037 Mcf per day in the first ninesix months of 20172020 compared to 417,722457,859 Mcf per day in the first ninesix months of 2016.2019. It processed an average of 133,986160,943 Mcf per day in the first ninesix months of 20172020 compared to 160,411163,725 Mcf per day in the first ninesix months of 2016.2019. The amount of NGLs sold was 518,054582,546 gallons per day in the first ninesix months of 20172020 compared to 536,911681,070 gallons per day in the first ninesix months of 2016.2019. Gas gathered volumes per day in the first ninesix months of 20172020 decreased 8%13% compared to the first ninesix months of 20162019 primarily due to declines in existingdeclining volumes fewerfrom most of our major systems partially offset by higher volumes on our Cashion system, due to new wells connected, and no offload volume at our Hemphill facility in 2017.well connects along with a new acquisition. Gas processed volumes for the first ninesix months of 20172020 decreased 16% from2% compared to the first ninesix months of 20162019 due to declines in existing volumes,connecting fewer new wells connected 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 no offload volume at our Hemphill facility in 2017. NGLs sold decreased 4% from the comparative period due to less volume available to process at our plants.

At-the-Market (ATM) Common Stock Program

On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent sharesoperating several of our common stock, parprocessing facilities in ethane rejection mode.

We determined that the carrying value $0.20 per share (the Shares), upof certain long-lived asset groups in southern Kansas, and central Oklahoma where lower pricing is expected to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility,impact drilling and general corporate purposes.
Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directlyproduction levels, are not recoverable and exceeded their estimated fair value. Based on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the termsestimated fair value of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rulesasset groups, we recorded non-cash impairment charges of the NYSE, to sell the Shares from time to time, based on$64.0 million. These charges are included within impairment charges in our instructions (including any price, time or size limits or other customary parameters or conditions we may impose).Consolidated Statement of Operations.
We do not have to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
As of October 20, 2017, we sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million.


Our Credit AgreementAgreements and Senior Subordinated Notes


Unit Credit Agreement. Our SeniorDue to the Credit Agreement (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 scheduledreflected 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 maturethe Credit Agreement Extension Condition is based on Aprilthe 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.

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
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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, 2020. Under2018, 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 amount we can borrowapplicable 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.

Superior is the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed $875.0 million. Our borrowing base and elected commitment is $475.0 million. We are charged a commitment fee of 0.50%0.375% on the amount available but not borrowed. That feeborrowed which varies based on the amount borrowed as a percentage of the total borrowing base. WeSuperior paid $1.0$1.7 million in origination, agency, syndication, and other related fees. WeThese fees are amortizing these feesbeing amortized over the life of the Superior credit agreement. Under the

The Superior credit agreement we pledgedrequires that Superior maintain a Consolidated EBITDA to interest expense ratio for the following collateral: (a) 85%most-recently ended rolling four quarters of the proved developed producing (discounted as present worth at 8%) total valueleast 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of our oilnot 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 gas propertiesleaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and (b) 100%acquire or dispose of our ownership interest in our mid-stream affiliate,assets. As of June 30, 2020, Superior Pipeline Company, L.L.C.complied with these covenants.


The currentborrowings 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 ourthe Superior credit agreement and their respective participation interests are:
Lender
Participation

Interest
BOK (BOKF, NA, dba Bank of Oklahoma)1717.50 %
Compass Bank1717.50 %
BMO Harris Financing, Inc.1513.75 %
Bank of America, N.A.15%
Comerica Bank8%
Wells Fargo Bank, N.A.8%
Canadian Imperial Bank of Commerce8%
Toronto Dominion (New York), LLC813.75 %
The Bank of Nova ScotiaAmerica, N.A.410.00 %
Branch Banking and Trust Company10010.00 %
Comerica Bank10.00 %
Canadian Imperial Bank of Commerce7.50 %
100.00%


The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1stSubordinated Notes. As of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. The October 2017 redetermination did not result in any changes. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the credit agreement.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base for the term plus 2.00% to 3.00% 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, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At September 30, 2017 and October 20, 2017, borrowings were $162.1 million and $162.7 million, respectively.

We can use borrowings for financing general working capital requirements for (a) exploration, development, production, and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services and acquisition of contract drilling equipment, and (e) general corporate purposes.

The credit agreement prohibits, among other things:

the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income for the preceding fiscal year;
the incurrence of additional debt with certain limited exceptions; and
the creation or existence of mortgages or liens, other than those in the ordinary course of business and with certain limited exceptions, on any of our properties, except in favor of our lenders.

The credit agreement also requires that we have at the end of each quarter:

a current ratio (as defined in the credit agreement) of not less than 1 to 1.

Through the quarter ending March 31, 2019, the credit agreement also requires that we have at the end of each quarter:

a senior indebtedness ratio of senior indebtedness to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four quarters of no greater than 2.75 to 1.

Beginning with the quarter ending June 30, 2019, and for each following quarter, the credit agreement requires:

a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.

As of September 30, 2017,2020, we were in compliance with the credit agreement covenants.

6.625% Senior Subordinated Notes. We havehad an aggregate principal amount of $650.0 million 6.625% senior subordinated notes (the Notes) outstanding.outstanding on the Notes. Interest on the Notes iswas 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 overuntil maturity. In the lifesecond quarter, we wrote off the remaining debt issuance costs due to the filing of the Notes.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.


The Notes arewere subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the 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
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Indenture), establishing the terms of and providing for issuing the Notes. The Guarantors are most of our direct and indirect subsidiaries. The discussionOn the Effective Date, by operation of the Plan, all outstanding obligations under the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.were cancelled.


Unit, as the parent company, has no significant independent assets or operations. The guarantees by the Guarantors of the Notes
(registered (registered under registration statements) arewere 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. AnySuperior was not a Guarantor of the Notes as of the Petition Date. Excluding Superior, any of our other subsidiaries that arewere not Guarantors arewere minor. There are no significant restrictions on our ability to receive funds from any of our subsidiariessubsidiary through dividends, loans, advances, or otherwise.


We may redeem all or, occasionally,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 part30-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. Pursuant to the Plan, each holder of the Notes will receive its pro rata share of New Common Stock based on equity allocations at certain redemption prices, plus accruedeach of Unit, UDC and unpaid interest. IfUPC 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 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 “changetwo-month extension to be approved by the DIP Lenders), (ii) the sale of control” occurs,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 certain conditions, we must offer to repurchase fromthe 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).

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.

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 any part ofABR Loans (each as defined in the exit credit agreement). Revolving Loans that holder’s Notesare Eurodollar Loans will bear interest at a purchase price in cashrate per annum equal to 101%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.
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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 million.

On the Effective Date, the Borrowers had (i) $40 million in principal amount of Term Loans outstanding under the Notes plus accruednew term loan facility, (ii) $92 million in principal amount of Revolving Loans outstanding under the new RBL facility and unpaid interest to the date(iii) approximately $6.68 million of purchase. The 2011 Indenture contains customary eventsoutstanding letters of default. The 2011 Indenture also contains covenants including those that limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of September 30, 2017.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 future growth.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 completed drilling 43participated in the completion of 27 gross wells (15.10(6.16 net wells) drilled by other operators in the first ninesix months of 20172020 compared to 1563 gross wells (7.77(17.41 net wells) drilled by Unit and other operators in which we participated in the first ninesix months of 2016.2019.

On April 3, 2017, we closed an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million. As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. This acquisition included 13 potential horizontal drilling locations not otherwise included in our existing acreage. Of the acreage acquired, approximately 71% was held by production. We also received one gathering system as part of the transaction.


Capital expenditures for oil and gas properties on the full cost method for the first ninesix months of 20172020 by this segment, excluding $56.4$0.2 million for acquisitions and a $2.8 million in the ARO liability, totaled $143.7 million. Capital expenditures for the first nine months of 2016, excluding a $29.4$3.4 million reduction in the ARO liability, totaled $91.9$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.


We plan to participate in drilling approximately 60 to 65 gross wells in 2017 and our total estimated capital expenditures (excluding any possible acquisitions) for this segment are approximately $216.0 million. WhetherFor 2020, we can drill the full number of wells planned depends on several factors, many of which are beyond our control, including the availability of drilling rigs, availability of pressure pumping services, prices for oil, NGLs, and natural gas, demand for oil, NGLs, and natural gas, the costdo not currently have plans to drill wells the weather, and the efforts of outside industry partners.pending our ability to refinance or restructure our debt.


Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. During the first quarter of 2017,2019, 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 awardedalso extended. The other BOSS drilling rig was delivered to a term contract to build our tenthnew 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 rig. Constructiondrilling rig was completed and the drilling rig was placed into service late in December of 2019 for a third party under a long-term contract. During the second quarter.quarter of 2019, two existing BOSS drilling rig contracts working for the same operator were also extended.


Our estimated 2017We have no commitments or plans to build any additional BOSS drilling rigs in 2020.

For 2020, we do not currently have an approved capital expendituresplan for this segment are approximately $38.0 million. At September 30, 2017, we had commitments to purchase approximately $3.9 million for drilling equipment over the next year.segment. Capital expenditures incurred would be within anticipated cash flows. We have spent $30.0$2.8 million for capital expenditures during the first ninesix months of 2017,2020, compared to $7.2$24.9 million for capital expenditures during the first ninesix months of 2016.2019.


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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In the Appalachian region ourat the Pittsburgh Mills gathering system, in Allegheny and Butler counties, continues to produce consistent financial results. Our average gathered volume for the thirdsecond quarter of 2017 is approximately 128.52020 was 181.8 MMcf per day. We connectedday while the average gathered volume for June 2020 was approximately 169.3 MMcf per day as the new AllenBakerstown wells started to decline. During the second quarter of 2020, we added one new infill well padto this system. This was the fourth and final well added to the Bakerstown pad.

At the Hemphill processing facility located in Maythe Texas panhandle, average total throughput volume for the second quarter of 2020 was 52.4 MMcf per day and it included five new wells.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 in the third quarter. We are constructing a pipeline to connect the Miller well pad, which will be the next pad connected to our system. The Miller pad will include seven new wells and we anticipate it will be ready to flow in the third quarter of 2018. Also, we anticipate several in-fill wells to be drilled and connected to ourthis system in the second halfquarter of 2018.2020. 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 our Hemphillthe Segno gathering system located in East Texas, system, our totalthe average throughput volume averaged 60.8for the second quarter of 2020 decreased to 42.4 MMcf per day fordue to declining production volume along with no new drilling activity in the thirdarea. During the second quarter of 2017 and our total production of natural gas liquids was approximately 164,000 gallons per day. During the third quarter,2020, we connected two new wells and since the beginning of 2017, we connected fourdid not connect any new wells to this processing facility. Our oil and gas segment continues to operate a rig and wesystem. We do not anticipate connecting two more wells in the fourth quarter.  

At our Cashion processing facility in central Oklahoma, our total throughput volume for the third quarter of 2017 averaged approximately 38.4 MMcf per day and our total production of natural gas liquids was approximately 196,000 gallons per day. Total processing capacity for this facility remains at approximately 45 MMcf per day. We connected fourany new wells to this system in the third quarter for a total of six new2020 but UPC will continue to perform some workovers in addition to some recompletions on existing wells connected in 2017. We completed a construction project that allows us to bring additional gas to this processing plant from a third party producer. This new producer will deliver fee-based volume to us for five years or will pay a shortfall fee settled annually. We are in the process of constructing a new pipeline extension which will allow us to connect a new producer to our system. We have connected one well from this producer and plan to connect two more wells in the fourth quarter.

At our Bellmon processing facility in the Mississippian play in north central Oklahoma, we connected two new wells in the third quarter of 2017 and since the beginning of 2017, we connected nine new wells to this processing facility. Our total throughput volume averaged approximately 27.5 MMcf per day. Total natural gas liquids averaged approximately 131,000 gallons per day while operating in ethane recovery mode at this facility. Total processing capacity at this system is approximately 90 MMcf per day.

At our Segno gathering facility in Southeast Texas, gathered volume for the third quarter of 2017 averaged approximately 81.5 MMcf per day. At this facility, we have increased our gathering and dehydration capacity to approximately 120 MMcf per day. We have connected two new wells to this system in 2017.


During the first ninesix months of 2017,2020, our mid-stream segment incurred $10.1$9.0 million in capital expenditures as compared to $11.1$32.6 million in the first ninesix months of 2016.2019. For 2017,2020, our estimated capital expenditures arewill be approximately $18.9$10.8 million.



Contractual Commitments


At SeptemberJune 30, 2017,2020, 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)
 $981,786
 $48,443
 $256,444
 $676,899
 $—
Operating leases (2)
 4,698
 3,209
 1,200
 289
 —
Capital lease interest and maintenance(3)
 7,653
 2,362
 4,254
 1,037
 —
Drill pipe, drilling components, and equipment purchases (4)
 3,887
 3,887
 —
 —
 —
Total contractual obligations $998,024
 $57,901
 $261,898
 $678,225
 $—
_______________________
(1)See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Notes and credit agreement and includes interest calculated using our September 30, 2017 interest rates of 6.625% for the Notes and 3.3% for the credit agreement. Our credit agreement has a maturity date of April 10, 2020.

(2)We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. 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 capital lease agreements. The capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining are $6.3 million and $1.3 million, respectively.

(4)We have committed to pay $3.9 million for drilling rig components, drill pipe, and related equipment over the year.

 Payments Due by Period
 TotalLess
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.

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.
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At SeptemberJune 30, 2017,2020, we also had the following commitments and contingencies that could create, increase, or accelerate our liabilities:
 Estimated Amount of Commitment Expiration Per Period
Other CommitmentsTotal
Accrued		Less
Than 1
Year		2-3
Years		4-5
Years		After 5
Years
 (In thousands)
Deferred compensation plan (1)
$6,006 UnknownUnknownUnknownUnknown
Separation benefit plans (2)
$22,624 UnknownUnknownUnknownUnknown
Asset retirement liability (3)
$64,248 $1,104 $2,988 $3,568 $56,588 
Gas balancing liability (4)
$3,823 UnknownUnknownUnknownUnknown
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 $— $— 
  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)
 $5,287
 Unknown
 Unknown
 Unknown
 Unknown
Separation benefit plans (2)
 $6,020
 $775
 Unknown
 Unknown
 Unknown
Asset retirement liability (3)
 $75,485
 $2,947
 $48,778
 $4,247
 $19,513
Gas balancing liability (4)
 $3,322
 Unknown
 Unknown
 Unknown
 Unknown
Repurchase obligations (5)
 $—
 Unknown
 Unknown
 Unknown
 Unknown
Workers’ compensation liability (6)
 $13,420
 $6,699
 $1,699
 $937
 $4,085
Capital leases obligations (7)
 $16,161
 $3,806
 $8,083
 $4,272
 $—
Other $—
 Unknown
 $—
 Unknown
 Unknown
_______________________ 
(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.

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.


(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).

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.
(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 formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the “Partnerships”) with certain qualified employees, officers and directors from 1984 through 2011. One of our subsidiaries serves as the general partner of each of these programs. Effective December 31, 2014, The Unit 1984 Oil and Gas Limited Partnership dissolved and effective December 31, 2016, the two 1986 partnerships were dissolved. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. Repurchases in any one year are limited to 20% of the units outstanding. We had no repurchases in the first nine months of 2016. We made repurchases of approximately $2,900 during the first nine months of 2017.

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


(7)The amount includes commitments under capital lease arrangements for compressors in our mid-stream segment.

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 SeptemberJune 30, 2017,2020, based on our thirdsecond quarter 20172020 average daily production, the approximated percentages of our production under derivative contracts are as follows:
2020
Daily oil production30 %
Daily natural gas production29 %
  Q3 Q4 Q1 Q2 Q3 Q4
  2017 2018
Daily oil production 54% 54% 58% 58% 58% 58%
Daily natural gas production 74% 64% 56% 28% 28% 28%


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 SeptemberJune 30, 20172020 evaluation, we believe the risk of non-performance by our counterparties is not material. At SeptemberJune 30, 2017,2020, the fair values of the net assets (liabilities) 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)
  September 30, 2017
  (In millions)
Bank of Montreal $0.9
Scotiabank (0.1)
Canadian Imperial Bank of Commerce (0.3)
Bank of America (0.4)
Total assets $0.1

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 SeptemberJune 30, 2017,2020, 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 $1.0$0.6 million and current and non-current derivative liabilities of $0.6 million and $0.3 million, respectively. At December 31, 2016, we recorded the fair value of our commodity derivatives on our balance sheet as non-current derivative assets of $0.4 million, and current and non-current derivative liabilities of $21.6 million and $0.4 million, respectively.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 SeptemberJune 30 are as follows:
Three Months EndedSix Months Ended
June 30,June 30,
2020201920202019
 (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 
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
  (In thousands)
Gain (loss) on derivatives:        
Gain (loss) on derivatives, included are amounts settled during the period of $840, ($457), ($729) and $11,735, respectively $(2,614) $6,969
 $21,019
 $(4,774)
  $(2,614) $6,969
 $21,019
 $(4,774)


Stock and Incentive Compensation


During the first ninesix months of 2017,2020, 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 698,2761,424,027 shares of restricted stock. These awards had an estimated fair value as of their grant date of $17.2$22.6 million. Compensation expense will be recognized over the three yearthree-year vesting periods, and during the ninesix months of 2017,2019, we recognized $5.0$3.4 million in compensation expense and capitalized $0.8$0.6 million for these awards. During the first ninesix months of 2017,2019, we recognized compensation expense of $9.0$8.5 million for all of

our restricted stock and stock options and SAR grants and capitalized $1.3 million of compensation cost forto oil and natural gas properties.

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During the first nine months of 2016, we granted awards covering 728,951 shares of restricted stock. These awards had an estimated fair value as of their grant date of $4.3 million. Compensation expense will be recognized over the three year vesting periods, and during the nine months of 2016, we recognized $1.1 million in compensation expense and capitalized $0.2 million for these awards. During the first nine months of 2016, we recognized compensation expense of $7.2 million for all of our restricted stock, stock options, and SAR grants and capitalized $1.6 million of compensation cost for oil and natural gas properties.


Insurance


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


Oil and Natural Gas Limited Partnerships and Other Entity Relationships


We arewere the general partner of 13 oil and natural gas partnerships which were formed privately or publicly. Each partnership’s revenues and costs arewere shared under formulas set out in that partnership’s agreement. The partnerships repayrepaid us for contract drilling, well supervision, and general and administrative expense. Related party transactions for contract drilling and well supervision fees arewere the related party’s share of such costs. These costs arewere billed on the same basis 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 as well asand indirect expenses assigned to the related parties. Allocations are based on the related party’s level of activity and arewere considered by us to be reasonable. For the first nine months of 2017 and 2016, the total we received for all of these fees was $0.1 million and $0.2 million, respectively. Our proportionate share of assets, liabilities, and net income (loss)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


Compensation—Stock Compensation. 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 2017-09,2016-13 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 clarifythe 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 reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms and conditions of a share-based payment award.other disclosures were added. The amendments areamendment is effective for reporting periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements.

Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the subsequent measurement of goodwill. The amendments eliminate Step 2 from the goodwill impairment test. The amendments will be effective prospectively for reporting periods beginning after December 31, 2019, and early2019. Early adoption is permitted. We do not believe these amendments will have a material impact on our financial statements.

Business Combinations; Clarifying the DefinitionThe adoption of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments.  The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. The amendments will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. We do not believe these amendments will have a material impact on our financial statements.

Leases. The FASB has issued ASU 2016-02. The amendments will require lessees to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor

accounting is largely unchanged. For public companies, the amendments are effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases of mineral rights. We are in the process of evaluating the impact these amendments will have on our financial statements.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. These amendments affect any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the amendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 has been amended several times pre-issuance, which will be codified in the new Topic 606, and it is effective January 1. 2018. Thethis guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. We will adopt these amendments January 1, 2018.

The new revenue standard provides a five-step analysis of transactions to determine the amount and timing of revenue recognition. Entities can choose to apply Topic 606 using either the full retrospective approach or a modified retrospective approach. We plan to adopt using the modified retrospective approach, which will result in a cumulative effect adjustment upon adoption.

Currently, management believes the effect of adoption will not have a material effect on our statement of operations or our balance sheet, as the timing of revenue recognized will not be materially modified, but the adoption will result in more robust footnote disclosures in regards to revenue. We anticipate a cumulative effect of applying the new revenue standard as an adjustment to the opening balance of retained earnings at the beginning of 2018 in relation to certain mid-stream segment and contract drilling segment contracts that include adjustments to the timing of revenue recognition of certain demand fee and mobilization/demobilization expenses and revenue, respectively. We believe this adjustment will not be material due to the short-term nature of the majority of our current contract drilling segment contracts and the limited number of mid-stream segment contracts with demand fees that we anticipate to be in place at the adoption date. Part of our review included evaluation of the following issues:

Based on an analysis of whether the transportation of gas is a performance obligation that occurs at a point in time or over time, the timing of when we recognize certain revenue elements will change. Specifically related to our mid-stream segment, certain fees that are collectible in the early stages of a contract will be recognized over the life of the contract because these fees are part of the single performance obligation associated with the contract.

Certain of our contracts include promises to deliver a minimum volume of commodity to the customer over a defined period of time. If we do not meet this commitment, a deficiency fee is payable to the customer. Topic 606 requires that these types of arrangements represent variable consideration related to the sale of the commodity, and requires that we include an estimate of any deficiency fees expected within revenue, rather than as operating costs. In addition, we will also be required to analyze fees that are billable for deficiencies in minimum volume commitments from customers for our mid-stream segment. In these instances, we will assess the likelihood of earning these fees each reporting period based on the customer’s performance and recognize variable revenue at the time it is not expected to be subject to a significant reversal.

Adopted Standards

Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations are required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments were effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments require current deferred tax assets to be combined with noncurrent deferred tax assets. We have adopted this ASU during the first quarter of 2017 on a prospective basis. Previously, we had a net current deferred tax asset which is now netted with our noncurrent deferred tax liability. Prior periods were not retrospectively adjusted.

Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments were effective for

annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments primarily impact classification within the statement of cash flows between financial and operating activities. This did not have a material impact on our consolidated financial statements.statements or related disclosures.

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Results of Operations
Quarter Ended SeptemberJune 30, 20172020 versus Quarter Ended SeptemberJune 30, 20162019
Provided below is a comparison of selected operating and financial data:
  Quarter Ended September 30, 
Percent
Change (1)
  2017 2016 
  (In thousands unless otherwise specified)  
Total revenue $188,488
 $153,408
 23 %
Net income (loss) $3,705
 $(24,022) 115 %
       
Oil and Natural Gas:      
Revenue $85,470
 $78,854
 8 %
Operating costs excluding depreciation, depletion, amortization, and impairment $33,911
 $26,014
 30 %
Depreciation, depletion, and amortization $26,460
 $27,135
 (2)%
Impairment of oil and natural gas properties $—
 $49,443
 (100)%
       
Average oil price received (Bbl) $47.29
 $42.79
 11 %
Average NGLs price received (Bbl) $18.35
 $12.68
 45 %
Average natural gas price received (Mcf) $2.36
 $2.29
 3 %
Oil production (Bbl) 633,000
 701,000
 (10)%
NGLs production (Bbl) 1,243,000
 1,260,000
 (1)%
Natural gas production (Mcf) 13,085,000
 13,399,000
 (2)%
Depreciation, depletion, and amortization rate (Boe) $6.18
 $6.06
 2 %
       
Contract Drilling:      
Revenue $51,619
 $25,819
 100 %
Operating costs excluding depreciation $34,747
 $19,137
 82 %
Depreciation $15,280
 $11,318
 35 %
       
Percentage of revenue from daywork contracts 100% 100% — %
Average number of drilling rigs in use 34.6
 16.0
 116 %
Average dayrate on daywork contracts $16,454
 $17,479
 (6)%
       
Mid-Stream:      
Revenue $51,399
 $48,735
 5 %
Operating costs excluding depreciation and amortization $38,116
 $35,738
 7 %
Depreciation and amortization $10,880
 $11,436
 (5)%
       
Gas gathered—Mcf/day 383,787
 429,693
 (11)%
Gas processed—Mcf/day 140,246
 152,651
 (8)%
Gas liquids sold—gallons/day 530,028
 558,843
 (5)%
       
Corporate and other:      
General and administrative expense $9,235
 $8,852
 4 %
Other depreciation $1,913
 $80
 NM
Gain on disposition of assets $81
 $154
 (47)%
Other income (expense):      
Interest expense, net $(9,944) $(10,002) (1)%
Gain (loss) on derivatives $(2,614) $6,969
 (138)%
Other $5
 $3
 67 %
Income tax expense (benefit) $1,769
 $(14,599) 112 %
Average long-term debt outstanding $804,617
 $866,249
 (7)%
Average interest rate 6.0% 5.7% 5 %
_________________________
(1)NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

 Quarter Ended June 30,
Percent
Change (1)
 20202019
(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 contracts100 %100 %— %
Average number of drilling rigs in use9.1 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/day404,831 465,714 (13)%
Gas processed--Mcf/day155,555 165,682 (6)%
Gas liquids sold--gallons/day637,420 711,192 (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 rate6.1 %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 increased $6.6decreased $50.9 million or 8%65% in the thirdsecond quarter of 20172020 as compared to the thirdsecond quarter of 20162019 primarily due to higherlower commodity prices partially offset from reduced productionand volumes. In the thirdsecond quarter of 2017,2020, as compared to the thirdsecond quarter of 2016,2019, oil production decreased 10%25%, natural gas production decreased 2%28%, and NGLs production decreased 1%29%. AverageIncluding derivatives settled, average oil prices increased 11%decreased 65% to $47.29$20.96 per barrel, average natural gas prices increased 3%decreased 42% to $2.36$1.08 per Mcf, and NGLs prices increased 45%decreased 67% to $18.35$4.11 per barrel.


Oil and natural gas operating costs increased $7.9$35.3 million or 30%97% between the comparative thirdsecond quarters of 20172020 and 20162019 primarily due to higher LOEa $45.0 million estimated litigation settlement and production taxesa $6.1 additional separation benefit expense due to a reduction in our workforce partially offset by lower saltwater disposal expenses.lease operating expenses (LOE) and gross production taxes.


Depreciation, depletion, and amortization (“DD&A”)(DD&A) decreased $0.7$16.7 million or 2%43% due primarily to a 3%22% decrease in the DD&A rate and a 28% decrease in equivalent production partially offset by a 2% increase in the DD&A rate.production. The increasedecrease in our DD&A rate in the thirdsecond quarter of 20172020 compared to the thirdsecond quarter of 20162019 resulted primarily from the cost of wells drilled in the first nine months of 2017.reduced net book value due to ceiling test write-down.


During the thirdsecond quarter of 2016,2020, we recorded a non-cash ceiling test write-down of $49.4109.3 million pre-tax ($30.8109.3 million, net of tax). We did not have a ceiling test write-down forin the thirdsecond quarter of 2017.2019.


Contract Drilling


Drilling revenues increased $25.8decreased $13.8 million or 100%32% in the thirdsecond quarter of 20172020 versus the thirdsecond quarter of 2016.2019. The increasedecrease was due primarily to a 116%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)
 20202019
(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 contracts100 %100 %— %
Average number of drilling rigs in use13.9 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 $— — %
Gas gathered--Mcf/day397,037 457,859 (13)%
Gas processed--Mcf/day160,943 163,725 (2)%
Gas liquids sold--gallons/day582,546 681,070 (14)%
Corporate and Other:
Loss on abandonment of assets$(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 rate6.2 %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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Table of Contents
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 6% decrease4% increase in the average dayrate. Average drilling rig utilization increaseddecreased from 16.030.0 drilling rigs in the third quarterfirst six months of 20162019 to 34.613.9 drilling rigs in the third quarterfirst six months of 2017.2020.


Drilling operating costs increased $15.6decreased $14.3 million or 82%24% between the comparative third quartersfirst six months of 20172020 and 2016.2019. The increasedecrease was due primarily to moreless drilling rigs operating.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 increased $4.0decreased $11.5 million or 35%44% in the first six months of 2020 versus the first six months of 2019 also due primarily to moreless drilling rigs operating.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 increased $2.7decreased $26.7 million or 5%28% in the third quarterfirst six months of 20172020 as compared to the third quarterfirst six months of 20162019 due primarily to increases inlower gas, NGLs, and condensate prices.prices and decreased liquids, condensate volumes, and gas sales. Gas processed volumes per day decreased 8%2% between the comparative quartersperiods primarily due to declines in existing volumes,connecting fewer new wells connected to our processing systems, and no offload volume at our Hemphill facility in 2017.systems. Gas gathered volumes per day decreased 11%13% between the comparative quartersperiods 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 declining gathered volumes on our Appalachian systems.

Operating costs increased $2.4 million or 7% in the third quarter of 2017 compared to the third quarter of 2016 primarily due to 26% higher gaslower purchase prices partially offset by a 9% decrease in purchasealong with lower purchased volumes. Depreciation and amortization decreased $0.6$1.2 million, or 5%, primarily due to certain assets being fully depreciatedimpairing the carrying value of several of our systems in 2017.

Other Depreciation

During the third quarter of 2017, we had $1.9 million of other depreciation primarily due to our new ERP accounting and reporting system that was implemented during the first quarter of 2017.2020.


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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 $0.4$17.6 million or 4%89% in the third quarterfirst six months of 20172020 as compared to the third quarterfirst six months of 20162019 primarily due to an increasehigher consulting and outside legal fees. We incurred $20.2 million in employee costs.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, decreased $0.1increased $3.3 million between the comparative third quartersfirst six months of 20172020 and 20162019 due primarily to a 7%an 18% decrease in average long-term debt outstanding and no capitalized interest in the third quarterfirst six months of 2017 and an increase in interest capitalized2020 partially offset by a higherlower average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction ofconstructing additional drilling rigs, and the construction ofconstructing gas gathering systems. CapitalizedBecause we are not currently undergoing any capital projects, we had no capitalized interest for the third quarterfirst six months of 2017 was $4.0 million2020 compared to $3.6$8.4 million infor the third quarterfirst six months of 2016,2019 and capitalized interest was netted against our gross interest of $14.0$20.9 million and $13.6$26.0 million for the third quartersfirst six months of 20172020 and

2016, 2019, respectively. Our average interest rate increaseddecreased from 5.7%6.5% in the third quarterfirst six months of 20162019 to 6.0%6.2% in the third quarterfirst six months of 20172020 and our average debt outstanding was $61.6decreased $124.4 million lower in the third quarterfirst six months of 2017 as2020 compared to the third quarterfirst six months of 20162019 primarily due to the decreaseNotes now being classified as liabilities subject to compromise in outstanding borrowings under our Unaudited Condensed Consolidated Balance Sheets.

Write-off of Debt Issuance Costs

Due to the remaining commitments of the Unit credit agreement overbeing terminated by the comparative periods.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 increased $9.6decreased by $7.4 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.


Income Tax Expense (Benefit)Benefit


Income tax expense increased $16.4benefit was a benefit of $9.9 million betweenin the comparative third quartersfirst six months of 2017 and 2016a benefit of 2020 compared to $2.3 million in the first six months of 2019 primarily due to increaseddecreased pre-tax income. Our effective tax rate was 32.3%0.96% for the third quarterfirst six months of 20172020 compared to 37.8%18.4% for the third quarterfirst six months of 2016.2019. The rate change was primarily due to the recognition of our Uncertain Tax Position associated with a research and development tax credit of $0.4 million. There was no current income tax expense or benefit infor the thirdsecond quarter of 2017 or 2016. We did not pay any income taxes in the third quarter of 2017.


Nine Months Ended September 30, 2017 versus Nine Months Ended September 30, 2016
Provided below is a comparison of selected operating and financial data:
  Nine Months Ended September 30, 
Percent
Change
  2017 2016 
  (In thousands unless otherwise specified)  
Total revenue $534,793
 $427,897
 25 %
Net income (loss) $28,693
 $(137,307) 121 %
       
Oil and Natural Gas:      
Revenue $256,241
 $206,318
 24 %
Operating costs excluding depreciation, depletion, amortization, and impairment $95,873
 $92,691
 3 %
Depreciation, depletion, and amortization $71,544
 $89,378
 (20)%
Impairment of oil and natural gas properties $—
 $161,563
 (100)%
       
Average oil price received (Bbl) $47.62
 $38.71
 23 %
Average NGLs price received (Bbl) $17.05
 $10.16
 68 %
Average natural gas price received (Mcf) $2.50
 $1.98
 26 %
Oil production (Bbl) 1,990,000
 2,260,000
 (12)%
NGLs production (Bbl) 3,476,000
 3,745,000
 (7)%
Natural gas production (Mcf) 37,317,000
 42,376,000
 (12)%
Depreciation, depletion, and amortization rate (Boe) $5.76
 $6.48
 (11)%
       
Contract Drilling:      
Revenue $128,059
 $88,786
 44 %
Operating costs excluding depreciation $91,213
 $66,489
 37 %
Depreciation $41,896
 $34,431
 22 %
       
Percentage of revenue from daywork contracts 100% 100% — %
Average number of drilling rigs in use 29.7
 16.7
 78 %
Average dayrate on daywork contracts $16,120
 $18,147
 (11)%
       
Mid-Stream:      
Revenue $150,493
 $132,793
 13 %
Operating costs excluding depreciation and amortization $111,862
 $99,185
 13 %
Depreciation and amortization $32,547
 $34,410
 (5)%
       
Gas gathered—Mcf/day 385,846
 417,722
 (8)%
Gas processed—Mcf/day 133,986
 160,411
 (16)%
Gas liquids sold—gallons/day 518,054
 536,911
 (4)%
       
Corporate and other:      
General and administrative expense $26,902
 $25,811
 4 %
Other depreciation $5,558
 $218
 NM
Gain on disposition of assets $1,153
 $823
 40 %
Other income (expense):      
Interest expense, net $(28,807) $(30,225) (5)%
Gain (loss) on derivatives $21,019
 $(4,774) NM
Other $14
 $(11) NM
Income tax expense (benefit) $22,084
 $(73,159) 130 %
Average long-term debt outstanding $811,159
 $882,330
 (8)%
Average interest rate 6.0% 5.6% 7 %


Oil and Natural Gas

Oil and natural gas revenues increased $49.9 million or 24% in the first nine months 2017 as compared to the first nine months of 2016 primarily due to higher commodity prices partially2020 being offset by lower production volumes. In the first nine months of 2017, as compared to the first nine months of 2016, oil production decreased 12%, natural gas production decreased 12%, and NGLs production decreased 7%. Average oil prices increased 23% to $47.62 per barrel, average natural gas prices increased 26% to $2.50 per Mcf, and NGLs prices increased 68% to $17.05 per barrel.

Oil and natural gas operating costs increased $3.2 million or 3% between the comparative first nine months of 2017 and 2016 due to higher LOE and gross production tax partially offset by lower saltwater disposal expense.

DD&A decreased $17.8 million or 20% due primarily to a 11% decrease in our DD&A rate and a 11% decrease in equivalent production. The decrease in our DD&A rate in the first nine months of 2017 compared to the first nine months of 2016 resulted primarily from the effect of the ceiling test write-downs throughout 2016.

During the first nine months of 2016, we recorded non-cash ceiling test write-downs of $161.6 million pre-tax ($100.6 million, net of tax).valuation allowance. We did not have a write-down for 2017.

Contract Drilling

Drilling revenues increased $39.3 million or 44% in the first nine months of 2017 versus the first nine months of 2016. The increase was due primarily to a 78% increase in the average number of drilling rigs in use partially offset by a 11% decrease in the average dayrate. Average drilling rig utilization increased from 16.7 drilling rigs in the first nine months of 2016 to 29.7 drilling rigs in the first nine months of 2017. We recorded $0.8 million in early termination revenue in the first nine months of 2017 compared to $3.1 million in the first nine months of 2016.

Drilling operating costs increased $24.7 million or 37% between the comparative first nine months of 2017 and 2016. The increase was due primarily to more drilling rigs operating. Contract drilling depreciation increased $7.5 million or 22% also due primarily to more drilling rigs operating.

Mid-Stream

Our mid-stream revenues increased $17.7 million or 13% in the first nine months of 2017 as compared to the first nine months of 2016 due primarily to increased gas, NGLs, and condensate prices partially offset by a decrease in gas processed volumes. Gas processed volumes per day decreased 16% between the comparative periods primarily due to declines in existing volumes, fewer new wells connected, and no offload volume at our Hemphill facility in 2017. Gas gathered volumes per day decreased 8% between the comparative periods primarily due declines in existing volumes, fewer new wells connected, and no offload volume at our Hemphill facility in 2017.

Operating costs increased $12.7 million or 13% in the first nine months of 2017 compared to the first nine months of 2016 primarily due to increased purchase prices partially offset by a decrease in gas purchased volumes. Depreciation and amortization decreased $1.9 million, or 5%, primarily due to certain assets being fully depreciated in 2017.

Other Depreciation

During the first nine months of 2017, we had $5.6 million of other depreciation primarily due to our new ERP accounting and reporting system that was implemented during the first quarter of 2017 as well as depreciation on our corporate building.

General and Administrative

Corporate general and administrative expenses increased $1.1 million or 4% in the first nine months of 2017 compared to the first nine months of 2016 primarily due to higher employee costs.

Gain on Disposition of Assets

There was an $1.2 million gain on disposition of assets in the first nine months of 2017 primarily due to the sale of a corporate aircraft and vehicles, compared to a gain of $0.8 million for the disposition of assets in the first nine months of 2016 primarily due to the sale of various rig components (including three top drives and power units), vehicles, and a drilling yard.


Other Income (Expense)

Interest expense, net of capitalized interest, decreased $1.4 million between the comparative first nine months of 2017 and 2016 due primarily to a 8% decrease in the average long-term debt outstanding and increase interest capitalized partially offset by a higher average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interestcurrent income tax benefit for the first ninesix months of 2017 was $11.9 million compared to $11.2 million in the first nine months of 2016, and was netted against our gross interest of $40.7 million and $41.4 million for the first nine months of 2017 and 2016, respectively. Our average interest rate increased from 5.6% to 6.0% and our average debt outstanding was $71.2 million lower in the first nine months of 2017 as compared to the first nine months of 2016 primarily due to the decrease in outstanding borrowings under our credit agreement over the comparative periods.

Gain (Loss) on Derivatives

Gain (loss) on derivatives increased $25.8 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Income Tax Expense (Benefit)

Income tax expense increased $95.2 million between the comparative first nine months of 2017 and 2016 primarily due to increased pre-tax income. Our effective tax rate was 43.5% for the first nine months of 2017 compared to 34.8% for the first nine months of 2016. The increase was primarily due to increased deferred tax expense related to our restricted stock vestings in both comparative periods. There was2019. We paid no current income tax expense or benefit in the first nine months of 2017 or 2016. We did not pay any income taxes in the first ninesix months of 2017.2020.


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Safe Harbor Statement

This report, including information included in, or incorporated by reference from, future filings by us with the SEC, as well as information contained in written material, press releases, and oral statements issued by or on our behalf, contain, or may contain, certain statements that are “forward-looking statements” within the meaningTable of federal securities laws. All statements, other than statements of historical facts, included or incorporated by reference in this report, which address activities, events, or developments which 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.Contents

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

the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
prices for oil, NGLs, and natural gas;
demand for oil, NGLs, and natural gas;
our exploration and drilling prospects;
the estimates of our proved oil, NGLs, and natural gas reserves;
oil, NGLs, and natural gas reserve potential;
development and infill drilling potential;
expansion and other development trends 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 initiatives relating to hydrocarbon fracturing impacting our costs and increasing operating restrictions or delays as well as other adverse impacts on our business;
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; and
our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods.

These statements are based on certain assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations, including:

the risk factors discussed in this report and in the documents we incorporate by reference;
general economic, market, or business conditions;
the availability of and nature of (or lack of) business opportunities that 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;
putative class action lawsuits that may result in substantial expenditures and divert management's attention; 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 the date of this report to reflect the occurrence of unanticipated events.

A more thorough discussion of forward-looking statements with the possible impact of some of these risks and uncertainties is provided in our Annual Report on Form 10-K filed with the SEC. We encourage you to get and read that document.

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 ninesix months 20172020 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 $398,000$662,000 per month ($4.87.9 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 $212,000$387,000 per month ($2.54.6 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 $372,000$560,000 per month ($4.56.7 million annualized) change in our pre-tax operating cash flow.


We use derivative transactions to manage some of the riskrisks 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 SeptemberJune 30, 2017, the following2020, these derivatives were outstanding:
TermCommodityContracted Volume
Weighted Average 

Fixed Price
Contracted Market
Oct'17Jul'20 - Dec'20Natural gas –- basis swap70,00030,000 MMBtu/day$3.038(0.275)IF – NYMEX (HH)NGPL TEXOK
Nov’17 – Dec'17Jul'20 - Dec'20Natural gas –- basis swap60,00020,000 MMBtu/day$2.960(0.455)IF – NYMEX (HH)PEPL
Jan’18 – Dec'18Jan'21 - Dec'21Natural gas –- basis swap20,00030,000 MMBtu/day$3.013(0.215)IF – NYMEX (HH)NGPL TEXOK
Nov’17 – Dec'17Jul'20 - Dec'20Natural gas – basis swap20,000 MMBtu/day$(0.215)IF – NYMEX (HH)
Jan’18 – Mar'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Nov’18 – Dec'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Oct'17Natural gas – collar20,000 MMBtu/day$2.88 - $3.10IF – NYMEX (HH)
Oct'17Natural gas – three-way collar15,00030,000 MMBtu/day$2.50 - $2.00$2.20 - $3.32$2.80IF –- NYMEX (HH)
Nov’17 – Dec'17Jul'20 - Sep'20Natural gas – three-way collar25,000 MMBtu/day$2.90 - $2.30 - $3.59IF – NYMEX (HH)
Jan'18 – Mar'18Natural gas – three-way collar60,000 MMBtu/day$3.29 - $2.63 - $4.07IF – NYMEX (HH)
Apr'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Oct’17 – Dec'17Crude oil – three-way- collar3,750112,000 Bbl/daymonth$49.7920.00 - $39.58$26.50WTI - $60.98WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar2,000 Bbl/day$47.50 - $37.50 - $56.08WTI – NYMEX
Jan'18 – Dec'18Crude oil – swap2,000 Bbl/day$50.140WTI – NYMEX


After SeptemberJune 30, 2017, the following derivative was2020, these derivatives were entered into:
TermCommodityContracted Volume
Weighted Average
Fixed Price
Contracted Market
Apr'18 – Oct'18Sep'20 - Dec'20Natural gas –- swap10,000 MMBtu/day$2.9902.72IF –- NYMEX (HH)
Apr'18 – Sep'18Sep'20 - Oct'21
Liquids –Natural gas - swap(1)
1,00020,000 MMBtu/day$2.77IF - NYMEX (HH)
Jan'21 - Oct'21Natural gas - swap30,000 MMBtu/day$2.85IF - NYMEX (HH)
Nov'21 - Dec'21Natural gas - swap45,000 MMBtu/day$2.90IF - NYMEX (HH)
Jan'22 - Dec'22Natural gas - collar35,000 MMBtu/day$2.50 - $2.68IF - NYMEX (HH)
Oct'20 - Dec'20Crude oil - swap4,000 Bbl/day$31.16443.35OPIS – Mont BelvieuWTI - NYMEX
Jan'21 - Dec'21Crude oil - swap3,000 Bbl/day$44.65WTI - NYMEX
_______________________

(1)    Type of liquid involved is propane.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 agreementagreements and the Notes. TheAt June 30, 2020, we had indebtedness of $124.0 million under the Unit credit agreement, at our election bears$34.0 million under the Superior credit agreement, and $8.0 million under the DIP credit agreement, all of which bore interest at variable rates based on the Prime Rate or the LIBOR Rate.floating rates. At our election, borrowings under ourthe 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 ninesix months of 2017,2020, a 1% increase in the floating rate would reduce our annual pre-tax cash flow by approximately $1.6$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 Chief Executive OfficerCEO and Chief Financial Officer,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 Chief Executive OfficerCEO and Chief Financial OfficerCFO concluded that our disclosure controls and procedures arewere not effective as of SeptemberJune 30, 2017 in ensuring the appropriate information is recorded, processed, summarized and reported in our periodic SEC filings relating2020 due to the company (including its consolidated subsidiaries) and is accumulated and communicated to the Chief Executive Officer, Chief Financial Officer, and management to allow timely decisions.

Changes in Internal Controls. In January 2017, we implemented a new ERP accounting and reporting system designed to upgrade our technology and improve the timeliness and quality of our financial and operational information. This new ERP system was not implemented in response to any 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, (ICFR). The implementationwe 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 ERP systemremediation 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 affectedtested the processes that constitute parteffectiveness of our ICFR and requires ongoing testing for effectiveness. The adoption of this new ERP system has not materially affected our ICFR.those controls.

Changes in Internal Controls. There were no other changes in our ICFR during the quarter ended SeptemberJune 30, 2017,2020, 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.al. v. Unit Petroleum Company, No. CJ-07-215, District Court of Latimer County, Oklahoma.

Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita Golightly, Melody Culberson, and Charlotte Abernathy are the Plaintiffs in this case and are royalty owners in oil and gas drilling and spacing units for which the company’s exploration segment distributes royalty. The Plaintiffs’ central allegation is that the company’s exploration segment has underpaid royalty obligations by deducting post-production costs or marketing related fees. Plaintiffs sought to pursue the case as a class action on behalf of persons who receive royalty from us for our Oklahoma, production. We have asserted several defenses including that the deductions are permitted under Oklahoma law. We have also asserted that the case should not be tried as a class action due to the materially different circumstances that determine what, if any, deductions are taken for each lease. On December 16, 2009, the trial court entered its order certifying the class. On May 11, 2012 the court of civil appeals reversed the trial court’s order certifying the class. The Plaintiffs petitioned the supreme court for certiorari and on October 8, 2012, the Plaintiff’s petition was denied. On January 22, 2013, the Plaintiffs filed a second request to certify a class of royalty owners that was slightly smaller than their first attempt. Since then, the Plaintiffs have further amended their proposed class to just include royalty owners entitled to royalties under certain leases located in Latimer, Le Flore, and Pittsburg Counties, Oklahoma. In July 2014, a second class certification hearing was held where, in addition to the defenses described above, we argued that the amended class definition is still deficient under the court of civil appeals opinion reversing the initial class certification. Closing arguments were held on December 2, 2014. There is no timetable for when the court will issue its ruling. The merits of Plaintiffs’ claims will remain stayed while class certification issues are pending.

(ii) 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 PetroleumOklahoma, and (iii) Chieftain Royalty Company styled Cockerell Oil Properties, Ltd., v. Unit Petroleum Companyin, No. CJ-16-230, District Court of 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 untimely royalty payments under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of royalty ownersFor further information, please see Part II – “Item 1. Legal Proceedings” in our Oklahoma wells. We haveQuarterly 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 several defenses includingby 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 case cannotequity pool in accordance with the Plan. As disputed claims, such as these lawsuits, are allowed, disallowed or otherwise resolved, adjustments will be properly certified as a class action because of the wide variety of circumstances that determine whether a royalty payment was timely made or has accrued interest under Oklahoma law. At this point, the court has not taken any action on the issue of class certification.

We continue to vigorously defend against each of the pending claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.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, if any, and in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016,2019 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 Annual Report on 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.


ExceptOther 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, 2016.2019 and Part II, Item 1A in our Form 10-Q for the quarter ended March 31, 2020.


We arerecently 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 subjectChapter 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 putative class action lawsuits thattheir duties or more easily attracted to other employment opportunities; and
•competitors may result in substantial expenditures and divert management's attention.take business away from us.


We are the subjectThe occurrence of putative class action lawsuits in Oklahoma with respect to the alleged failure to pay interest with on untimely royalty payments and with respect to the alleged underpayment of royalties. These lawsuits seek various remedies, including damages, injunctive relief, and attorney’s fees. For additional information on these lawsuits, see Item 1 Legal Proceedings in this Quarterly Report on Form 10-Q.

Although we believe that the allegations in these lawsuits are without merit and intend to defend such litigation vigorously, litigation is subject to inherent uncertainties, and an adverse result in one or more of these lawsuits or other matters that may arise from time to timeevents 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 resultsstrategies.

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 operations and financial condition. Defending the lawsuits may be costly and, further, could require significant involvementall or substantially all of our senior managementassets;
•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 divert management's attention fromelect 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 operations.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 SeptemberJune 30, 2017:2020:
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
July 1, 2017 to July 31, 2017—
$—
—
—
August 1, 2017 to August 31, 2017—
—
—
—
September 1, 2017 to September 30, 2017—
—
—
—
Total—
$—
—
—
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, 2020174 $0.34 174 — 
May 1, 2020 to May 31, 2020— — — — 
 June 1, 2020 to June 30, 2020— — — — 
Total174 $0.34 174 — 


Item 3. Defaults Upon Senior Securities


Not applicable.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
31.13.2
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
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10.14
31.1
31.2
32
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema Document.
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.
101.LABXBRL Taxonomy Extension Labels Linkbase Document.
101.PREXBRL 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:Unit Corporation
Date:November 2, 2017October 21, 2020
By: /s/ Larry D. Pinkston
LARRY D. PINKSTON
Chief Executive Officer and Director
Date:November 2, 2017
By: /s/ David T. Merrill
DAVID T. MERRILL
President and Chief Executive Officer
Date:October 21, 2020
Chief Operating Officer,By: /s/ Les Austin
LES AUSTIN
Senior Vice President and Chief Financial Officer
and Treasurer



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