Table of Contents

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 September 30, 2017March 31, 2021
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-20210331_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 ☐          No ☒ *
Yes [x]            No [  ]                                                     
* Effective January 1, 2021, the registrant’s obligation to file reports under 15(d) of the Securities Exchange Act of 1934 was automatically suspended.
Indicate by check mark whether the registrant has submitted electronically 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

Table of October 20, 2017, 52,879,660 shares of the issuer's common stock were outstanding.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 30, 2017 and December 31, 2016
34
Unaudited Condensed Consolidated Statements of Operations
Three and Nine Months Ended September 30, 2017 and 2016
5
Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)
Three and Nine Months Ended September 30, 2017 and 2016
6
Unaudited Condensed Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2017 and 2016
7
911
Item 2.
3032
Item 3.
5439
Item 4.
5640
PART II. Other Information
Item 1.
5642
Item 1A.
5742
Item 2.
5742
Item 3.
5742
Item 4.
5742
Item 5.
5842
Item 6.
5942
6042


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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 SECUnited States Securities Exchange Commission (SEC) will automatically update and supersede information in this report.
TheseForward-looking statements are not guarantees of performance. They involve risks, uncertainties, and assumptions. Future actions, conditions or events, and future results may differ materially from those expressed in our forward-looking statements. Many factors that will determine these results are beyond our ability to control or accurately predict. Specific factors that could cause actual results to differ from those in our forward-looking statements include, among others, things as:include:


•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),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 ofin the oil and natural gas industry;
•our business strategy;
•our plans to maintain or increase the production of oil, NGLs, and natural gas;
•the number of gathering systems and processing plants we may plan to construct or acquire;
•volumes and prices for the natural gas gatheredwe gather and processed;process;
•expansion and growth of our business and operations;
•demand for our drilling rigs and drilling rig rates;the rates we charge for the rigs;
•our belief that the final outcome of our 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, NGLs, or natural gas production to establishedexisting pipeline systems;
•the impact of federal and state legislative and regulatory actions affecting our costs and increasing operating restrictions or delays and other adverse impacts on our business;
•the possibility of security threats, including terrorist attacks and cybersecurity breaches, against or otherwise affecting our facilities and systems;
•any projected production guidelines for the year;we may issue;
•our anticipated capital budgets;
•our financial condition and liquidity;
•the number of wells our oil and natural gas segment plans to drill or rework during the year; anddrill;
•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 ability to carry out our post reorganization plans.
These statements are based on assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and expected future developments, and other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform tomeet 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:predictions. Some of these risk and uncertainties are:
•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 orand regulations;
•changes in the current geopolitical situation;
•risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
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•risks associated with future weather conditions;
•decreases or increases in commodity prices;
putative class action lawsuits that may result•the amount and terms of our debt;
•future compliance with covenants under our credit agreements;
•our ability to remediate a material weakness in substantial expendituresour internal controls over financial reporting;
•pandemics, epidemics, outbreaks, or other public health events, such as COVID-19; and divert management's attention; and
•other factors, most of which are beyond our control.
You should not placeconstrue this list to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that the actions, events, or results expressed in forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on theseany forward-looking statements. Except as required by law, we disclaim any intentionobligation 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 incorrect assumptions or unanticipated events.


Additional discussion of factors that may affect our forward-looking statements appear elsewhere in this report, including in Item 1A “Risk Factors,” Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 3uantitative and Qualitative Disclosures About Market Risk-Energy Commodity Market Risk.”

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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31,
2021		December 31,
2020
 (In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents$25,188 $12,145 
Restricted cash0 569 
Accounts receivable, net of allowance for credit losses of $4,265 and $3,783 at March 31, 2021 and December 31, 2020, respectively59,863 57,846 
Current income tax receivable34 1,150 
Prepaid expenses and other8,444 11,212 
Total current assets93,529 82,922 
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties240,285 238,581 
Unproved properties not being amortized49 1,591 
Drilling equipment63,764 63,687 
Gas gathering and processing equipment252,463 251,404 
Land and building32,635 32,635 
Transportation equipment3,335 3,130 
Other8,667 9,961 
601,198 600,989 
Less accumulated depreciation, depletion, amortization, and impairment71,921 54,189 
Net property and equipment529,277 546,800 
Right of use asset (Note 13)4,443 5,592 
Other assets15,616 14,389 
Total assets (1)
$642,865 $649,703 

  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
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED

March 31,
2021		December 31,
2020
 (In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable$34,552 $37,368 
Accrued liabilities (Note 7)23,108 25,204 
Current operating lease liability (Note 13)3,648 4,075 
Current portion of long-term debt (Note 8)800 600 
Current derivative liabilities (Note 11)14,022 1,047 
Warrant liability (Note 12)885 885 
Current portion of other long-term liabilities (Note 8)10,418 11,168 
Total current liabilities87,433 80,347 
Long-term debt (Note 8)78,200 98,400 
Non-current derivative liabilities (Note 11)11,211 4,659 
Operating lease liability (Note 13)741 1,445 
Other long-term liabilities (Note 8)40,188 39,259 
Commitments and contingencies (Note 14)00
Shareholders’ equity:
Preferred stock, $0.01 par value, 1,000,000 shares authorized, NaN issued0 0 
Common stock, $0.01 par value, 25,000,000 shares authorized, 12,000,000 shares issued as of March 31, 2021 and December 31, 2020120 120 
Capital in excess of par value197,316 197,242 
Retained deficit(20,077)(18,140)
Total shareholders’ equity attributable to Unit Corporation177,359 179,222 
Non-controlling interests in consolidated subsidiaries247,733 246,371 
Total shareholders' equity425,092 425,593 
Total liabilities(1) and shareholders’ equity
$642,865 $649,703 
_______________________
  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 March 31, 2021 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $55.7 million and $239.7 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of March 31, 2021 include total current and long-term liabilities of the VIE of $29.6 million and $1.7 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, 2020 include total current and long-term assets of the VIE of $45.8 million and $247.8 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2020 include total current and long-term liabilities of the VIE of $28.4 million and $2.6 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 15 – Variable Interest Entity Arrangements.













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

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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
SuccessorPredecessor
Three Months Ended March 31, 2021Three Months Ended March 31, 2020
 (In thousands except per share amounts)
Revenues:
Oil and natural gas$55,024 $48,522 
Contract drilling15,674 36,632 
Gas gathering and processing50,199 37,222 
Total revenues120,897 122,376 
Expenses:
Operating costs:
Oil and natural gas19,149 30,663 
Contract drilling11,871 25,449 
Gas gathering and processing40,543 27,611 
Total operating costs71,563 83,723 
Depreciation, depletion, and amortization17,511 61,617 
Impairments (Note 3)0 741,924 
Loss on abandonment of assets (Note 3)0 17,554 
General and administrative6,289 11,553 
(Gain) loss on disposition of assets(472)390 
Total operating expenses94,891 916,761 
Income (loss) from operations26,006 (794,385)
Other income (expense):
Interest, net(2,706)(13,257)
Gain (loss) on derivatives(22,831)483 
Reorganization items, net(1,136)0 
Other, net76 60 
Total other income (expense)(26,597)(12,714)
Loss before income taxes(591)(807,099)
Income tax benefit:
Current0 (917)
Deferred0 (2,508)
Total income taxes0 (3,425)
Net loss(591)(803,674)
Net income (loss) attributable to non-controlling interest1,346 (33,180)
Net loss attributable to Unit Corporation(1,937)(770,494)
Net loss attributable to Unit Corporation per common share (Note 6):
Basic$(0.16)$(14.50)
Diluted$(0.16)$(14.50)

  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
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)CHANGES IN SHAREHOLDERS’ EQUITY (UNAUDITED)
Three Months Ended March 31, 2021
Shareholders' Equity Attributable to Unit Corporation
Common
Stock		Capital in Excess
of Par Value		Retained
Earnings (Deficit)		Non-controlling Interest in Consolidated SubsidiariesTotal
(In thousands except per share amounts)
Balances, December 31, 2020 (Successor)$120 $197,242 $(18,140)$246,371 $425,593 
Net income (loss)0 0 (1,937)1,346 (591)
Activity in employee compensation plans0 74 0 16 90 
Balances, March 31, 2021 (Successor)$120 $197,316 $(20,077)$247,733 $425,092 

 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)
Three Months Ended March 31, 2020
Shareholders' Equity Attributable to Unit Corporation
Common
Stock		Capital in Excess
of Par Value		Retained
Earnings (Deficit)		Non-controlling Interest in Consolidated SubsidiariesTotal
(In thousands except per share amounts)
Balances, December 31, 2019 (Predecessor)$10,591 $644,152 $199,135 $201,757 $1,055,635 
Net loss0 0 (770,494)(33,180)(803,674)
Activity in employee compensation plans103 2,391 0 31 2,525 
Balances, March 31, 2020 (Predecessor)$10,694 $646,543 $(571,359)$168,608 $254,486 





























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

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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 SuccessorPredecessor
 Three Months Ended March 31, 2021Three Months Ended March 31, 2020
 (In thousands)
OPERATING ACTIVITIES:
Net loss$(591)$(803,674)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization17,511 61,617 
Impairments (Note 3)0 741,924 
Loss on abandonment of assets (Note 3)0 17,554 
Amortization of debt issuance costs and debt discount0 567 
(Gain) loss on derivatives (Note 11)22,831 (483)
Cash receipts (payments) on derivatives settled (Note 11)(3,304)551 
(Gain) loss on disposition of assets(472)390 
Deferred tax benefit0 (2,508)
Employee stock compensation plans90 2,568 
Credit loss expense482 0 
ARO liability accretion (Note 9)461 596 
Contract assets and liabilities, net (Note 4)812 808 
Noncash reorganization items760 0 
Other, net(79)(740)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable(2,498)28,277 
Material and supplies0 35 
Prepaid expenses and other1,586 420 
Accounts payable(4,043)(12,341)
Accrued liabilities(4,287)(4,840)
Income taxes1,116 (917)
Contract advances(71)108 
Net cash provided by operating activities30,304 29,912 
INVESTING ACTIVITIES:
Capital expenditures(2,034)(17,528)
Producing properties and other acquisitions0 (210)
Proceeds from disposition of property and equipment4,462 1,751 
Net cash provided by (used in) investing activities2,428 (15,987)
FINANCING ACTIVITIES:
Borrowings under line of credit2,700 71,400 
Payments under line of credit(22,700)(35,100)
Net payments on finance leases(1,067)(1,026)
Employee taxes paid by withholding shares0 (43)
Bank overdrafts809 (8,733)
Net cash provided by (used in) financing activities(20,258)26,498 
Net increase in cash, restricted cash and cash equivalents12,474 40,423 
Cash, restricted cash, and cash equivalents, beginning of period12,714 571 
Cash, restricted cash, and cash equivalents, end of period$25,188 $40,994 
  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




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


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

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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - CONTINUED
 SuccessorPredecessor
 Three Months Ended March 31, 2021Three Months Ended March 31, 2020
 (In thousands)
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Interest paid (net of capitalized)$2,438 $2,141 
Income taxes(1,116)0 
Reorganization items377 0 
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment(1,920)4,812 
Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations(26)3,404 
Non-cash trade of property, plant, and equipment0 548 







































The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1 – BASIS OF PREPARATIONORGANIZATION AND PRESENTATIONBUSINESS


The unaudited condensed consolidated financial statementsUnless the context clearly indicates otherwise, references 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,”to “Unit”, “company”, “we”, “our”, “us”, or like terms refer to Unit Corporation a Delaware corporation, andor, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers to Superior of which we own 50%.

We are primarily engaged in the development, acquisition, and production of oil and natural gas properties, the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas. Our operations are all in the United States and are organized in the following three reporting segments: (1) Oil and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream.

Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company (UPC), we develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Kansas, Louisiana, Montana, North Dakota, Utah, and Wyoming.

Contract Drilling. Carried out by our subsidiary, Unit Drilling Company (UDC), we drill onshore oil and natural gas wells for a wide range of other oil and natural gas companies as well as for our own account. Our drilling operations are mainly in Oklahoma, Texas, New Mexico, Wyoming, and North Dakota.

Mid-Stream. Carried out by our subsidiary, Superior, we buy, sell, gather, transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

On May 22, 2020 (Petition Date), Unit together with its wholly owned subsidiaries, UDC; UPC; 8200 Unit Drive, L.L.C. (8200 Unit); Unit Drilling Colombia, L.L.C. (Unit Drilling Colombia); and affiliates, except as otherwise indicated or asUnit Drilling USA Colombia, L.L.C. (Unit Drilling USA, together with Unit, UPC, UDC, 8200 Unit and Unit Drilling Colombia, the context otherwise requires.Debtors), filed voluntary petitions (Bankruptcy Petitions) for reorganization under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court). The Chapter 11 proceedings were jointly administered under Case No. 20-32740 (DRJ) (Chapter 11 Cases).On August 6, 2020, the Bankruptcy Court entered the “Findings of Fact, Conclusions of Law, and Order (I) Approving the Disclosure Statement on a Final Basis and (II) Confirming the Debtors’ Amended Joint Chapter 11 Plan of Reorganization” (the Plan) [Docket No. 340] (Confirmation Order) confirming the Plan and approving the disclosure statement on a final basis. On September 3, 2020 (Effective Date) the conditions to effectiveness for the Plan were satisfied, and the Debtors emerged from Chapter 11.


The condensed consolidated
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in our annualthe United States of America (GAAP) for complete consolidated financial statements. This reportstatements, and should be read in conjunction with the audited consolidated financial statements and notes in our Form 10-K, filed February 28, 2017,thereto for the year ended December 31, 2016.2020 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 31, 2021.


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

Balance Sheets at September 30, 2017 and December 31, 2016;
Statements of Operations for the three and nine months ended September 30, 2017 and 2016;
Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 and 2016; and
Statements of Cash Flows for the nine months ended September 30, 2017 and 2016.

stated. 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. ResultsThe results for the nine months ended September 30, 2017 and 2016interim periods are not necessarily indicative of annual results.

In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 852, Reorganizations, the resultsCompany adopted fresh start accounting upon emergence from the Chapter 11 Cases resulting in the Company becoming a new entity for financial reporting purposes. We evaluated the events between September 1, 2020 and September 3, 2020 and concluded that the use of an accounting convenience date of September 1, 2020 (Fresh Start Reporting
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Date) would not have a material impact to be realizedthe condensed consolidated financial statements. This was reflected in our condensed consolidated balance sheet as of September 1, 2020. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 1, 2020, are not comparable to the Condensed Consolidated Financial Statements and Notes before that date. To facilitate the financial statement presentations, we refer to the reorganized company in these unaudited condensed consolidated financial statements and notes as the "Successor" for the full year of 2017, or that we realizedperiods subsequent to August 31, 2020, and "Predecessor" for the full year of 2016.

Certain amounts inperiods prior to September 1, 2020. Furthermore, the unaudited condensed consolidated financial statements and notes have been presented with a "black line" division to delineate the lack of comparability between the Predecessor and Successor.

We consolidate the activities of Superior Pipeline Company, L.L.C. (Superior), a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, (SP Investor) which qualifies as a Variable Interest Entity (VIE) under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power to direct those activities that most significantly affect the economic performance of Superior as further described in Note 15 – Variable Interest Entity Arrangements.

Certain amounts in this report for prior periods have been reclassified to conform to current year presentation. There was no impact from these reclassifications to consolidated net income income/(loss) or shareholders' equity.


Recent Accounting Pronouncements

Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 which provides optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The ASU is intended to help stakeholders during the global market-wide reference rate transition period. The amendments within this ASU will be in effect for a limited time beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. The amendments will not have a material impact on our consolidated financial statements.

Adopted Standards

Income Taxes (Topic 740)—Simplifying the Accounting for Income Taxes. The FASB issued ASU 2019-12 to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendments were effective for reporting periods beginning after December 15, 2020. This standard had no material impact on our consolidated financial statements.

NOTE 23 – OIL AND NATURAL GAS PROPERTIESIMPAIRMENTS

FullWe review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of those assets may not be recoverable, and changes to our estimates could affect our assessment of asset recoverability.

Oil and Natural Gas Properties

There were no impairments recorded during the Successor Period of the three months ended March 31, 2021.

During the first quarter of 2020, due to the increased uncertainty in our business, we determined our undeveloped acreage would not be fully developed and thus the carrying values of certain of our unproved oil and gas properties were not recoverable resulting in an impairment of $226.5 million. That impairment had a corresponding increase to our depletion base and contributed to our recorded full cost accounting rules require usceiling impairment during the first quarter of 2020. We recorded a non-cash full cost ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax) in the first quarter of 2020 due to reviewthe reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above.

In addition to the impairment evaluations of our proved and unproved oil and gas properties in the first quarter of 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast, we determined that some were no longer expected to be used and wrote off the assets for total expense of $17.6 million during the first quarter of 2020. These amounts are reported in loss on abandonment of assets in our Unaudited Condensed Consolidated Statements of Operations.


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Contract Drilling

There were no impairments recorded during the Successor Period of the three months ended March 31, 2021.

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

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

We concluded that no impairment was needed as of March 31, 2020 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. 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

There were no impairments recorded during the Successor Period of the three months ended March 31, 2021.

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

NOTE 4 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is how we disaggregate our revenue and report our segment revenue (as reflected in Note 16 – Industry Segment Information). Revenue from the oil and natural gas segment is from sales of our oil and natural gas properties atproduction. Revenue from the endcontract drilling segment comes from contracting with upstream companies to drill an agreed-on number of each quarter. Underwells 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 rules, the maximum amount allowed commodities.

Oil and Natural Gas Revenues

Certain costs—as the carrying value is referred toeither a deduction from revenue or as the ceiling. The ceiling is the suman expense—are determined based on when control 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 amountcommodity is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short while. Once incurred, a write-down of oil and natural gas properties is not reversible.

We incurred non-cash ceiling test write-downs in the first nine months of 2016 of $161.6 million ($100.6 million net of tax). We did not have a write-down in the first nine months of 2017.

NOTE 3 – ACQUISITIONS AND DIVESTITURES

Acquisitions

On April 3, 2017, we closed on 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 acrestransferred 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.contract price with the customer on transfer of control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity represent operating costs.


Contract Drilling Revenues

Mobilization and de-mobilization charges from our drilling contracts do not relate to a distinct good or service. These revenues should be deferred and recognized ratably over the related contract term that drilling services are provided. We accountedhave continued to record these revenues as a distinct service and the impact to our financial statements was immaterial. As of March 31, 2021, we had 6 contract drilling contracts with terms ranging from two months to almost one year.

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

Mid-stream Contracts Revenues

Revenues are generated from fees earned for gas gathering and processing services provided to a customer or by selling hydrocarbons to other mid-stream companies. The typical revenue contracts used by this acquisition usingsegment are gas gathering and processing agreements as well as product sales.

Contracts for gas gathering and processing services may include terms for demand fees or shortfall fees. Demand fees represent an arrangement where a customer agrees to pay a fixed fee for a contractually agreed upon pipeline capacity, which results in performance obligations for each individual period of reservation. Once the acquisition method underservices have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized.

The table below shows the changes in our mid-stream contract asset and contract liability balances during periods presented associated with demand fees and the impact to gas gathering and processing revenues:

Classification on the Consolidated Balance SheetsMarch 31,
2021		December 31,
2020		Change
(In thousands)
Assets
Current contract assetsPrepaid expenses and other$4,735 $6,084 $(1,349)
Non-current contract assetsOther assets0 173 (173)
Total contract assets$4,735 $6,257 $(1,522)
Liabilities
Current contract liabilitiesCurrent portion of other long-term liabilities$2,332 $2,583 $(251)
Non-current contract liabilitiesOther long-term liabilities1,130 1,589 (459)
Total contract liabilities3,462 4,172 (710)
Contract assets (liabilities), net$1,273 $2,085 $(812)
Included below is the adjustment to demand fees from adopting ASC 805, Business Combinations, which requires that606 over the acquired assets and liabilities be recorded at their fair valuesremaining term of the contracts as of March 31, 2021.
ContractRemaining Term of Contract202120222023 and beyondTotal Remaining Impact to Revenue
(In thousands)
Demand fee contracts2 - 8 years$(2,689)$1,380 $36 $(1,273)

NOTE 5 – DIVESTITURES

Oil and Natural Gas

On March 30, 2021, the acquisition date. The following table summarizes the adjustedcompany entered into a purchase priceand sale agreement to which we agreed to sell substantially all of our wells and the estimated values of assets acquiredleases related thereto located in Reno and liabilities assumed. It is based on information available to us at the time these unaudited condensed consolidated financial statements were prepared. We believe these estimates are reasonable; however, the estimates areStafford Counties, Kansas for $7.1 million, subject to change as additional information becomes availablecustomary closing and is assessed by us (in thousands):post-closing adjustments. This divestiture closed on May 6, 2021, with an effective date of February 1, 2021. The sale of these assets will not result in a significant alteration of the full cost pool, and therefore no gain or loss will be recognized.
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.
The pro forma effects of this acquired business is immaterial to the results of operations.

During the third quarter of 2017, we had approximately $2.1 million in other acquisitions.

Divestitures


We sold $1.7 million of non-core oil and natural gas assets, net of related expenses, for $18.0during the first three months of the Successor Period 2021, compared to $0.6 million during the first ninethree months of 2017, compared to $43.6 million during the first nine months of 2016. Proceeds from those salesPredecessor Period 2020. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.


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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:
Loss
(Numerator)		Weighted
Shares
(Denominator)		Per-Share
Amount
 (In thousands except per share amounts)
For the three months ended March 31, 2021 (Successor)
Basic loss attributable to Unit Corporation per common share$(1,937)12,000 $(0.16)
For the three months ended March 31, 2020 (Predecessor)
Basic loss attributable to Unit Corporation per common share$(770,494)53,131 $(14.50)

All outstanding shares issued during the Predecessor period were cancelled upon emergence from bankruptcy.

  
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
  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 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:
  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:
March 31,
2021		December 31,
2020
 (In thousands)
Employee costs$6,198 $8,878 
Lease operating expenses6,114 6,405 
Capital expenditures5,212 3,461 
Taxes3,396 2,324 
Interest payable300 884 
Legal settlement0 2,070 
Other1,888 1,182 
Total accrued liabilities$23,108 $25,204 
  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

NOTE 68 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES


Long-Term Debt


OurAs of the date indicated, our long-term debt consisted of the following:
March 31,
2021		December 31,
2020
 (In thousands)
Current portion of long-term debt:
Exit credit agreement with an average interest rate of 6.7% and 6.6% at March 31, 2021 and December 31, 2020, respectively$800 $600 
Long-term debt:
Exit credit agreement with an average interest rate of 6.7% and 6.6% at March 31, 2021 and December 31, 2020, respectively$78,200 $98,400 

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

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

On April 6, 2021, the company finalized the first amendment to the Exit credit agreement. Under the first amendment, the company reaffirmed its borrowing base of $140.0 million of the following:RBL, amended certain financial covenants, and received less restrictive terms, among others, as it relates to the disposition of assets and the use of proceeds from those dispositions.

  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
The Exit credit agreement requires the company to comply with certain financial ratios, including a covenant that the company will not permit the Net Leverage Ratio (as defined in the Exit credit agreement) as of the last day of the fiscal quarters ending (i) December 31, 2020 and March 31, 2021, to be greater than 4.00 to 1.00, (ii) June 30, 2021, September 30, 2021, December 31, 2021, March 31, 2022, and June 30, 2022, to be greater than 3.75 to 1.00, and (iii) September 30, 2022 and any fiscal quarter thereafter, to be greater than 3.50 to 1.00. In addition, beginning with the fiscal quarter ending December 31, 2020, the company may not (a) permit the Current Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 1.00 to 1.00 or (b) permit the Interest Coverage Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 2.50 to 1.00. The Exit credit agreement also contains provisions, among others, that limit certain capital expenditures, and require certain hedging activities. The Exit credit agreement further requires the company provide Quarterly Financial Statements within 45 days after the end of each of the first three quarters of each fiscal year and Annual Financial Statements within 90 days after the end of each fiscal year. As of March 31, 2021, Unit was in compliance with these covenants.


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

At March 31, 2021, we had $0.8 million and $78.2 million outstanding current and long-term borrowings, respectively, under the Exit credit agreement.

Superior Credit Agreement. Our Senior Credit Agreement (credit agreement) is scheduledOn May 10, 2018, Superior signed a five-year, $200.0 million senior secured revolving credit facility with an option to mature on April 10, 2020. Underincrease the credit amount up to $250.0 million, subject to certain conditions (Superior credit agreement). The maturity date of borrowings under the Superior credit agreement is March 10, 2023. The amounts borrowed under the amount we can borrowSuperior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) the Thirty-Day LIBOR Rate (as defined in the Superior credit agreement)) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by mortgage liens on certain of Superior’s processing plants and gathering systems. The Superior credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to the Administrative Agent in the London Interbank Market, the Administrative Agent may select a replacement index.

Superior is 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 pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownershiprequires that Superior maintain a Consolidated EBITDA to interest in our mid-stream affiliate, Superior Pipeline Company, L.L.C.

The borrowing base amount–which is subject to redetermination by 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 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 baseexpense ratio 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, we had $162.1 million of outstanding borrowings 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.

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 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 defined in the credit agreement) for the most recently ended rolling four fiscal quartersratio of nonot greater than 44.00 to 1.

1.00. The agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As of September 30, 2017, we wereMarch 31, 2021, Superior was in compliance with thethese covenants.
The Superior credit agreement covenants.is used to fund capital expenditures and acquisitions and provide general working capital and letters of credit. As of March 31, 2021, we did not have any outstanding borrowings under our Superior credit agreement.

6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million, 6.625% senior subordinated notes (the Notes) outstanding. Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes mature on May 15, 2021. In issuing the Notes, we incurred fees of $14.7 million that are being amortized as debt issuance cost over the life of the Notes.

The Notes are 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), 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 discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.


Unit as the parent company, has no independent assets or operations. The guarantees by the Guarantorsis not a party to and does not guarantee Superior's credit agreement.

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Table of the NotesContents
(registered under registration statements) are 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. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of our subsidiaries through dividends, loans, advances, or otherwise.

We may redeem all or, occasionally, a part 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 repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. The 2011 Indenture contains customary events 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.



Other Long-Term Liabilities


Other long-term liabilities consisted of the following:
March 31,
2021		December 31,
2020
 (In thousands)
Asset retirement obligation (ARO) liability$23,843 $23,356 
Workers’ compensation11,735 10,164 
Finance lease obligations2,149 3,216 
Contract liability3,462 4,172 
Separation benefit plans3,859 4,201 
Gas balancing liability4,238 3,997 
Other long-term liability1,320 1,321 
50,606 50,427 
Less current portion10,418 11,168 
Total other long-term liabilities$40,188 $39,259 

  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

Estimated annual principal payments under the terms of debt and other long-term liabilities during the five successive twelve month periods beginning October 1, 2017 (and through 2022) are $14.2 million, $48.3 million, $172.4 million, $657.0 million, and $2.5 million, respectively.

Capital Leases

In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $3.8 million 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 September 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.

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:
SuccessorPredecessor
 Three Months Ended March 31, 2021Three Months Ended March 31, 2020
 (In thousands)
ARO liability, January 1:$23,356 $66,627 
Accretion of discount461 596 
Liability incurred0 314 
Liability settled(16)(319)
Liability sold(2)(15)
Revision of estimates (1)
44 (3,384)
ARO liability, March 31:23,843 63,819 
Less current portion2,161 1,470 
Total long-term ARO$21,682 $62,349 
  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
1.Plugging liability estimates were revised in 2020 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS

Compensation—Stock Compensation. The FASB issued ASU 2017-09, to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms and conditionscost of a share-based payment award. The amendments are 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,services used 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 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. The 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 recognizedplug wells over the life of the contract because these fees are part of the single performance obligation associated with the contract.preceding year. We had various upward and downward adjustments.


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 financial statements.

NOTE 9 –STOCK-BASED10 – STOCK-BASED COMPENSATION


On the Effective Date, the Board adopted the Unit Corporation Long Term Incentive Plan (LTIP) to incentivize employees, officers, directors and other service providers of the company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Board or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, performance awards, substitute awards or any combination of the foregoing. Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the LTIP, 903,226 shares of new common stock of the reorganized company (New Common Stock) have been reserved for issuance pursuant to awards under the LTIP. New Common Stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash, or otherwise terminated without delivery of shares and shares
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withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the LTIP. The LTIP will be administered by the Board or a committee thereof.

No shares under the LTIP have been awarded since the Effective Date through March 31, 2021.

Also on the Effective Date, the company's equity-based awards outstanding immediately before the Effective Date were cancelled. The cancellation of the awards resulted in an acceleration of unrecorded stock compensation expense during the Predecessor Period. Under the Plan, the company issued Warrants to holders of those equity-based awards that were outstanding immediately before the Effective Date who did not opt out of releases under the Plan.

For restricted stock awards and stock options, we had:
Predecessor
Three Months Ended March 31, 2020
(In millions)
Recognized stock compensation expense$2.5 
Tax benefit on stock-based compensation$0.6 
  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 September 30, 2017 is approximately $14.2 million, of which $1.7 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is one year.

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 as to non-employee directors. A total of 7,000,000 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."

We did not grant any SARs or stock options during either of the threeor nine month periods ending September 30, 2017 or 2016. We did not grant any restricted stock awards during either of the three month periodsperiod ending September 30, 2017 or 2016. The following table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated:March 31, 2020.


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

The time vested restricted stock awards granted during the first nine months of 2017 and 2016 are being recognized over a three-year vesting period. During the first two quarters of 2017 and the first quarter of 2016, there were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures 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, one-third each year, over a

three-year vesting period subject to the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected performance criteria at September 30, 2017, the participants are estimated to receive 81% of 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 vest 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 of 2017 was $5.8 million.

NOTE 1011 – DERIVATIVES


Commodity Derivatives


We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions.conditions as well as certain requirements stipulated in the Exit credit agreement. For further details, see Note 8 – Long-Term Debt and Other Long-Term Liabilities. As of September 30, 2017,March 31, 2021, our derivative transactions were comprisedconsisted of the following types of hedges:


•Basis/Differential Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the commodity and pay or receive the published index price at the specified delivery point. We use basis/differential swaps to hedge the price risk between NYMEX and its physical delivery points.
•Swaps. We receive or pay a fixed price for the commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

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 basis 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. All derivatives are recognized on the balance sheet and measured at fair value. Any changes in theour derivatives' fair value of our derivative transactions 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.


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At September 30, 2017, the followingMarch 31, 2021, these derivatives were outstanding:
TermCommodityContracted Volume
Weighted Average��
Average 
Fixed Price
Contracted Market
Oct'17Apr'21 - Dec'21Natural gas –- basis swap70,00030,000 MMBtu/day$3.038(0.215)NGPL TEXOK
Apr'21 - Oct'21Natural gas - swap50,000 MMBtu/day$2.818IF –- NYMEX (HH)
Nov’17 – Dec'17Nov'21 - Dec'21Natural gas –- swap60,00045,000 MMBtu/day$2.9602.900IF –- NYMEX (HH)
Jan’18 – Dec'18Jan'22 - Dec'22Natural gas –- swap20,0005,000 MMBtu/day$3.0132.605IF –- NYMEX (HH)
Nov’17 – Dec'17Jan'23 - Dec'23Natural gas – basis- swap20,00022,000 MMBtu/day$(0.215)2.456IF –- NYMEX (HH)
Jan’18 – Mar'18Jan'22 - Dec'22Natural gas – basis swap- collar10,00035,000 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 collar15,000 MMBtu/day$2.50 - $2.00$2.68IF - $3.32IF – NYMEX (HH)
Nov’17 – Dec'17Apr'21 - Dec'21Natural gas – three-way collarCrude oil - swap25,000 MMBtu/3,373 Bbl/day$2.9046.16WTI - $2.30 - $3.59IF – NYMEX (HH)
Jan'18 – Mar'18Jan'22 - Dec'22Natural gas – three-way collarCrude oil - swap60,000 MMBtu/2,300 Bbl/day$3.2942.25WTI - $2.63 - $4.07IF – NYMEX (HH)
Apr'18 – Dec'18Jan'23 - Dec'23Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Oct’17 – Dec'17Crude oil – three-way collar- swap3,7501,300 Bbl/day$49.7943.60WTI - $39.58 - $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 Liabilities
  Fair Value
 Balance Sheet LocationMarch 31,
2021		December 31,
2020
  (In thousands)
Commodity derivatives:
CurrentCurrent derivative liability$14,022 $1,047 
Long-termNon-current derivative liability11,211 4,659 
Total derivative liabilities$25,233 $5,706 
    Derivative Assets
    Fair Value
  Balance Sheet Location September 30,
2017		 December 31,
2016
    (In thousands)
Commodity derivatives:      
Current Current derivative asset $1,064
 $—
Long-term Non-current derivative asset —
 377
Total derivative assets   $1,064
 $377

    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:
SuccessorPredecessor
Three Months Ended March 31, 2021Three Months Ended March 31, 2020
 (In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $(3,304) and $551, respectively$(22,831)$483 
$(22,831)$483 
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.


Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30:
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 1112 – 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.


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•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.


The following tables set forth our recurring fair value measurements:
 March 31, 2021
 Level 2Level 3Effect
of Netting		Net Amounts Presented
 
Financial assets (liabilities):
Commodity derivatives:
Assets$1,899 $0 $(1,899)$0 
Liabilities(27,132)0 1,899 (25,233)
Total commodity derivatives$(25,233)$0 $0 $(25,233)
 December 31, 2020
 Level 2Level 3Effect
of Netting		Net Amounts Presented
 
Financial assets (liabilities):
Commodity derivatives:
Assets$3,436 $0 $(3,436)$0 
Liabilities(9,142)0 3,436 (5,706)
Total commodity derivatives$(5,706)0 0 (5,706)
  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, 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 September 30, 2017.March 31, 2021.



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

Level 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 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 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.

 Net Derivatives
SuccessorPredecessor
Three Months Ended March 31, 2021Three Months Ended March 31, 2020
 (In thousands)
Beginning of period$0 $1,204 
Total gains or losses (realized and unrealized):
Included in earnings (1)
0 563 
Settlements0 (819)
End of period$0 $948 
Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period$0 $(256)
The following table provides quantitative information about our Level 3 unobservable inputs at September 30, 2017:_______________________
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
 _______________________
(1)The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and 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.

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

Our valuation at September 30, 2017March 31, 2021 reflected that the risk of non-performance by our counterparties was immaterial.


Warrants. Warrants are recorded at their fair value upon utilizing the Black-Scholes-Merton option model. The inputs to the model require judgement, including estimating the strike price, expected term and the associated volatility. At March 31, 2021, the Warrants have a fair value of $0.9 million and will continue to be adjusted to fair value at each reporting period until determined to be an equity instrument, at which time they will be reported as Shareholders' equity and no longer be subject to future fair value adjustment.

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 September 30, 2017,March 31, 2021, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents, (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, 2016 were $641.7 million and $640.1 million, respectively. We estimate the fair value of the Notes using quoted marked prices at September 30, 2017 and December 31, 2016 was $654.6 million and $649.9 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 13 – LEASES

Lease Agreements. We lease certain office space, land, and equipment, including pipeline equipment and office equipment. Our lease payments are generally straight-line and the exercise of lease renewal options, which vary in term, is at our sole discretion. We include renewal periods in our lease term if we are reasonably certain to exercise available renewal options. Our lease agreements do not include options to purchase the leased property.

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The following table sets forth the maturity of our operating lease liabilities as of March 31, 2021:
Amount
(In thousands)
Ending March 31,
2022$3,760 
2023661 
202429 
202512 
202612 
2027 and beyond60 
Total future payments4,534 
Less: Interest145 
Present value of future minimum operating lease payments4,389 
Less: Current portion3,648 
Total long-term operating lease payments$741 

Finance Leasesunder ASC 842

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 $2.1 million current portion of the finance lease obligations is included in current portion of other long-term liabilities in the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2021. These finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases were $0.1 million at March 31, 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 March 31, 2021:
Amount
Ending March 31,(In thousands)
2022$2,226 
Total future payments2,226 
Less payments related to:
Maintenance72 
Interest5 
Present value of future minimum finance lease payments2,149 
Less: Current portion2,149 
Total long-term finance lease payments$0 

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The following table shows information about our lease assets and liabilities in our Unaudited Condensed Consolidated Balance Sheets:
Classification on the Consolidated Balance SheetMarch 31,
2021		December 31,
2020
(In thousands)
Assets
Operating right of use assetsRight of use assets$4,443 $5,592 
Finance right of use assetsProperty, plant, and equipment, net7,032 7,281 
Total right of use assets$11,475 $12,873 
Liabilities
Current liabilities:
Operating lease liabilitiesCurrent operating lease liabilities$3,648 $4,075 
Finance lease liabilitiesCurrent portion of other long-term liabilities2,149 3,216 
Non-current liabilities:
Operating lease liabilitiesOperating lease liabilities741 1,445 
Finance lease liabilitiesOther long-term liabilities0 0 
Total lease liabilities$6,538 $8,736 

The following table shows certain information related to the lease costs for our finance and operating leases for the periods indicated:
SuccessorPredecessor
Three Months Ended March 31, 2021Three Months Ended March 31, 2020
(In thousands)
Components of total lease cost:
Amortization of finance leased assets$1,067 $1,025 
Interest on finance lease liabilities29 70 
Operating lease cost1,047 1,244 
Short-term lease cost (1)
1,444 3,991 
Variable lease cost58 82 
Total lease cost$3,645 $6,412 
_______________________
1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $0.1 million and $1.0 million for the first three months of 2021 and 2020, respectively.

The following table shows supplemental cash flow information related to leases for the periods indicated:
SuccessorPredecessor
Three Months Ended March 31, 2021Three Months Ended March 31, 2020
(In thousands)
Cash paid for amounts in the measurement of lease liabilities:
Operating cash flows for operating leases$1,048 $1,333 
Financing cash flows for finance leases$1,067 $1,025 

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The following table shows certain information related to the weighted average remaining lease terms and the weighted average discount rates for our operating and finance leases:
Weighted Average Remaining Lease Term
Weighted Average Discount
Rate (1)
(In years)
Operating leases1.44.30%
Finance leases0.44.00%
_______________________
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.

NOTE 1214 – COMMITMENTS AND CONTINGENCIES


Commitments

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. We also have several compressor rentals, equipment leases, and lease space on short-termfirm transportation commitments to stack excess drilling rig equipment and production inventory.Future minimum rental payments under the terms of the leases aretransport our natural gas from various systems for approximately $3.2 million, $0.8 million $0.4 million,over the next twelve months and $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 thereafter.

During the second quarter of 2017 and 2016, respectively.

In 2014, our mid-stream segment2018, as part of the Superior transaction (see Note 15 – Variable Interest Entity Arrangements), we entered into capital lease agreements for 20 compressors with initial terms of seven years. Estimated annual capital lease payments undera contractual obligation committing us to spend $150.0 million to drill wells in the terms during the four successive twelve month periods beginning OctoberGranite Wash/Buffalo Wallow area over three years starting January 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 end2019. For each dollar of the term,$150.0 million we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our ownership interest in our consolidated mid-stream segment has the optionsubsidiary. At March 31, 2021, if we elected not to purchase the assets at 10% of their then fair market value.

The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal. Indrill or spend any one year, these repurchases are limited to 20% of the units outstanding. We had no repurchasesadditional money in the first nine monthsdesignated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.6 million. The total amount spent towards the $150.0 million as of 2016.March 31, 2021 was $24.8 million. We made repurchases of $2,900 duringdo not anticipate meeting the first nine months of 2017.contractual obligation over the remaining commitment period.


Environmental

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


We have not historically experienced anysignificant 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.


ForLitigation

The company is subject to litigation and claims arising in the next twelve months,ordinary course of business which may include environmental, health and safety matters, or more routine employment related claims. The company accrues for such items when a liability is both probable and the amount can be reasonably estimated. As new information becomes available or because of legal or administrative rulings in similar matters or a change in applicable law, the company's conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. Although we are insured against various risks, there is no assurance that the nature and amount of that insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.

On May 22, 2020, the Debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 Cases automatically stayed all the proceedings and actions against the Debtors (other than certain regulatory enforcement matters). The Debtors emerged from the Chapter 11 Cases on the Effective Date. On the Effective Date, the automatic stay was terminated and replaced with the injunction provisions in the Confirmation Order and the Plan.
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In 2013, the company’s exploration and production subsidiary, UPC, drilled a well in Beaver County, Oklahoma. Certain operational issues arose and one of the working interest owners in the well filed a lawsuit claiming that UPC’s actions violated its duties under the joint operating agreement and caused damages to the owners in the well. The case went to trial in January 2019 and the jury issued a verdict in favor of the working interest owner, awarding $2.4 million in damages, including pre- and post-judgment interest. UPC appealed the verdict, and while it was pending review in the Oklahoma Court of Civil Appeals, UPC finalized a settlement agreement with the working interest owner for $2.1 million in February 2021.

The commencement of the Chapter 11 Cases automatically stayed all proceedings and actions against the Predecessor company (other than certain regulatory enforcement matters). Effective at emergence from the Chapter 11 Cases, the automatic stay was terminated and replaced with the injunction provisions in the Confirmation Order and the Plan.

Below is a summary of two lawsuits and the respective treatment of those cases in the Chapter 11 Cases.

Cockerell Oil Properties, Ltd., v. Unit Petroleum Company, No. 16-cv-135-JHP, United States District Court for the         
Eastern District of Oklahoma.

On March 11, 2016, a putative class action lawsuit was filed against UPC styled Cockerell Oil Properties, Ltd., v. Unit Petroleum Company in LeFlore County, Oklahoma. We removed the case to federal court in the Eastern District of Oklahoma. The plaintiff alleges that UPC wrongfully failed to pay interest with respect to late paid oil and gas proceeds under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney fees. Plaintiff is seeking relief on behalf of royalty and working interest owners in our Oklahoma wells.

Chieftain Royalty Company v. Unit Petroleum Company, No. CJ-16-230, District Court of LeFlore County, Oklahoma.

On November 3, 2016, a putative class action lawsuit was filed against UPC styled Chieftain Royalty Company v. Unit Petroleum Company in LeFlore County, Oklahoma. The plaintiff alleges that UPC breached its duty to pay royalties on natural gas used for fuel off the lease premises. The lawsuit seeks actual and punitive damages, an accounting, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of Oklahoma citizens who are or were royalty owners in our Oklahoma wells.

Pending Settlement

In August 2020, UPC reached an agreement to settle these class actions. Under the settlement, UPC agreed to recognize class proof of claims in the amount of $15.75 million for Cockerell Oil Properties, Ltd. vs. Unit Petroleum Company, and $29.25 million in Chieftain Royalty Company vs. Unit Petroleum Company. 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 Plan, these settlements will be treated as allowed general unsecured claims against UPC. And, in accordance with the Plan, the settlement amounts will be satisfied by distribution of the plaintiffs’ proportionate share of New Common Stock.

Winter Storm

In February 2021, a severe winter storm impacted many of our operating areas in Oklahoma, Texas, and Kansas, resulting in certain disruptions to our operations. Although some uncertainties remain as to the ultimate impact and severity of these disruptions, we do not believe any such matters will have committed to purchase approximately $3.9 million of new drilling rig components.a material impact on our financial position.



NOTE 1315 – EQUITYVARIABLE INTEREST ENTITY ARRANGEMENTS

At-the-Market (ATM) Common Stock Program


On April 4, 2017,3, 2018 we entered intosold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor Holdings, LLC, a Distributionholding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior is governed and managed under the Amended and Restated Limited Liability Company Agreement (Agreement) and a Management Services Agreement (MSA). The MSA is between our wholly-owned subsidiary, SPC Midstream Operating, L.L.C. (the Agreement)Operator) and Superior. As the Operator, we provide services, like operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $263,280. Superior's creditors have no recourse to our general credit. Unit is not a party to and does not guarantee Superior's credit agreement. The obligations under Superior's credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.

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The Agreement specifies how future distributions are to be allocated among the Members. Future distributions may be from available cash or made in conjunction with a 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 not fulfilling the drilling commitment described in Note 14 – 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, the 7% Liquidation IRR Hurdle calculation requires cumulative distributions to SP Investor Holdings, LLC in excess of its original $300.0 million investment sufficient to provide SP Investor Holdings, LLC a 7% IRR on its capital contributions to Superior before any liquidation distribution is made directly onto Unit. After the NYSE, on any other existing trading market forfifth anniversary of the Shareseffective date of the sale, either owner may force a sale of Superior to a third-party or a liquidation of Superior's assets.

Effective at emergence from the Chapter 11 Cases, we record our share of earnings and losses from Superior using the HLBV method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if Superior were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our unaudited condensed consolidated statements of operations. On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements.

Under the guidance in ASC 810, Consolidation, we have determined that Superior is a VIE. The two variable interests applicable to or throughUnit 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 market maker. In addition, underseparate variable interest. Under the Agreement,MSA, Unit has the sales agent may sellpower to direct Superior’s most significant activities; reciprocally the Shares by any other method permitted by law, including in privately negotiated transactions. Subjectequity investors lack the power to direct the activities that most affect the entity’s economic performance. Because of this, Unit is considered the primary beneficiary. There have been no changes to the termsprimary beneficiary during the quarter ended March 31, 2021.

As the primary beneficiary of this VIE, we consolidate in our financial statements the financial position, results of operations, and conditionscash flows of this VIE. All intercompany balances and transactions between us and the Agreement,VIE are eliminated in our consolidated financial statements. Cash distributions of income, net of agreed on expenses, and estimated expenses are allocated to the sales agent will use commercially reasonable efforts,equity owners as specified in the relevant agreements.

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The amounts below reflect the eliminations of intercompany transactions and balances consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules ofpresentation in 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).Unaudited Condensed Consolidated Balance Sheets.
March 31,
2021		December 31,
2020
 (In thousands)
Current assets:
Cash and cash equivalents$24,687 $11,642 
Accounts receivable25,890 27,427 
Prepaid expenses and other5,157 6,746 
Total current assets55,734 45,815 
Property and equipment:
Gas gathering and processing equipment252,463 251,403 
Transportation equipment1,822 1,748 
254,285 253,151 
Less accumulated depreciation, depletion, amortization, and impairment18,673 10,466 
Net property and equipment235,612 242,685 
Right of use asset2,384 2,823 
Other assets1,663 2,309 
Total assets$295,393 $293,632 
Current liabilities:
Accounts payable$20,200 $17,045 
Accrued liabilities3,164 3,777 
Current operating lease liability1,771 1,762 
Current portion of other long-term liabilities4,481 5,799 
Total current liabilities29,616 28,383 
Operating lease liability566 1,013 
Other long-term liabilities1,130 1,589 
Total liabilities$31,312 $30,985 

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 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 September 30, 2017, we sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million.

Accumulated Other Comprehensive Income

Components of accumulated other comprehensive income 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:
  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 1416 – INDUSTRY SEGMENT INFORMATION


We have three main business segments offering different products and services within the energy industry:
 
•Oil and natural gas,
•Contract drilling, and
•Mid-stream


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


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



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

Successor
 Three Months Ended September 30, 2016Three Months Ended March 31, 2021
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated Oil and Natural GasContract DrillingMid-streamCorporate and OtherEliminationsTotal Consolidated
 (In thousands) (In thousands)
Revenues:(1)            
Oil and natural gas $78,854
 $—
 $—
 $—
 $—
 $78,854
Oil and natural gas$55,025 $0 $0 $0 $(1)$55,024 
Contract drilling —
 25,819
 —
 —
 —
 25,819
Contract drilling0 15,674 0 0 0 15,674 
Gas gathering and processing —
 —
 63,090
 —
 (14,355) 48,735
Gas gathering and processing0 0 59,610 0 (9,411)50,199 
Total revenues 78,854
 25,819
 63,090
 —
 (14,355) 153,408
Total revenues55,025 15,674 59,610 0 (9,412)120,897 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 27,710
 —
 —
 —
 (1,696) 26,014
Oil and natural gas19,993 0 0 0 (844)19,149 
Contract drilling —
 19,137
 —
 —
 —
 19,137
Contract drilling0 11,871 0 0 0 11,871 
Gas gathering and processing —
 —
 48,397
 —
 (12,659) 35,738
Gas gathering and processing0 0 49,111 0 (8,568)40,543 
Total operating costs 27,710
 19,137
 48,397
 —
 (14,355) 80,889
Total operating costs19,993 11,871 49,111 0 (9,412)71,563 
Depreciation, depletion, and amortization 27,135
 11,318
 11,436
 80
 —
 49,969
Depreciation, depletion, and amortization7,655 1,575 8,032 249 0 17,511 
Impairments 49,443
 —
 —
 —
 —
 49,443
Total expenses 104,288
 30,455
 59,833
 80
 (14,355) 180,301
Total expenses27,648 13,446 57,143 249 (9,412)89,074 
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 6,289 0 6,289 
(Gain) loss on disposition of assets(Gain) loss on disposition of assets(19)(529)75 1 0 (472)
Income (loss) from operationsIncome (loss) from operations27,396 2,757 2,392 (6,539)0 26,006 
Loss on derivativesLoss on derivatives0 0 0 (22,831)0 (22,831)
Interest, netInterest, net0 0 (1,057)(1,649)0 (2,706)
Reorganization items, netReorganization items, net0 0 0 (1,136)0 (1,136)
Other —
 —
 —
 3
 —
 3
Other57 5 12 2 0 76 
Income (loss) before income taxes $(25,434) $(4,485) $3,257
 $(11,959) $—
 $(38,621)Income (loss) before income taxes$27,453 $2,762 $1,347 $(32,153)$0 $(591)
_______________________
(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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Predecessor
 Nine Months Ended September 30, 2017Three Months Ended March 31, 2020
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated Oil and Natural GasContract DrillingMid-streamCorporate and OtherEliminationsTotal Consolidated
 (In thousands) (In thousands)
Revenues:(1)            
Oil and natural gas $256,241
 $—
 $—
 $—
 $—
 $256,241
Oil and natural gas$48,524 $0 $0 $0 $(2)$48,522 
Contract drilling —
 137,617
 —
 —
 (9,558) 128,059
Contract drilling0 36,632 0 0 0 36,632 
Gas gathering and processing —
 —
 198,632
 —
 (48,139) 150,493
Gas gathering and processing0 0 42,680 0 (5,458)37,222 
Total revenues 256,241
 137,617
 198,632
 —
 (57,697) 534,793
Total revenues48,524 36,632 42,680 0 (5,460)122,376 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 99,349
 —
 —
 —
 (3,476) 95,873
Oil and natural gas31,415 0 0 0 (752)30,663 
Contract drilling —
 99,794
 —
 —
 (8,581) 91,213
Contract drilling0 25,449 0 0 0 25,449 
Gas gathering and processing —
 —
 156,525
 —
 (44,663) 111,862
Gas gathering and processing0 0 32,319 0 (4,708)27,611 
Total operating costs 99,349
 99,794
 156,525
 —
 (56,720) 298,948
Total operating costs31,415 25,449 32,319 0 (5,460)83,723 
Depreciation, depletion, and amortization 71,544
 41,896
 32,547
 5,558
 —
 151,545
Depreciation, depletion, and amortization36,728 11,745 12,273 871 0 61,617 
ImpairmentsImpairments267,836 410,126 63,962 0 0 741,924 
Total expenses 170,893
 141,690
 189,072
 5,558
 (56,720) 450,493
Total expenses335,979 447,320 108,554 871 (5,460)887,264 
Total operating income (loss)(1)
 85,348
 (4,073) 9,560
 (5,558) (977)  
General and administrative expense —
 —
 —
 (26,902) —
 (26,902)
Gain on disposition of assets 176
 106
 58
 813
 —
 1,153
Loss on abandonment of assetsLoss on abandonment of assets17,554 0 0 0 0 17,554 
General and administrativeGeneral and administrative0 0 0 11,553 0 11,553 
(Gain) loss on disposition of assets(Gain) loss on disposition of assets(13)409 (6)0 0 390 
Loss from operationsLoss from operations(304,996)(411,097)(65,868)(12,424)0 (794,385)
Gain on derivatives —
 —
 —
 21,019
 —
 21,019
Gain on derivatives0 0 0 483 0 483 
Interest expense, net —
 —
 —
 (28,807) —
 (28,807)
Interest, netInterest, net0 0 (518)(12,739)0 (13,257)
Other —
 —
 —
 14
 —
 14
Other18 17 18 7 0 60 
Income (loss) before income taxes $85,524
 $(3,967) $9,618
 $(39,421) $(977) $50,777
Loss before income taxesLoss before income taxes$(304,978)$(411,080)$(66,368)$(24,673)0 $(807,099)
_______________________
(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.


NOTE 17 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

For the following footnote:

•we 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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  Nine Months Ended September 30, 2016
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues:            
Oil and natural gas $206,318
 $—
 $—
 $—
 $—
 $206,318
Contract drilling —
 88,786
 —
 —
 —
 88,786
Gas gathering and processing —
 —
 168,668
 —
 (35,875) 132,793
Total revenues 206,318
 88,786
 168,668
 —
 (35,875) 427,897
Expenses:            
Operating costs:            
Oil and natural gas 98,070
 —
 —
 —
 (5,379) 92,691
Contract drilling —
 66,489
 —
 —
 —
 66,489
Gas gathering and processing —
 —
 129,681
 —
 (30,496) 99,185
Total operating costs 98,070
 66,489
 129,681
 —
 (35,875) 258,365
Depreciation, depletion, and amortization 89,378
 34,431
 34,410
 218
 —
 158,437
Impairments 161,563
 —
 —
 —
 —
 161,563
Total expenses 349,011
 100,920
 164,091
 218
 (35,875) 578,365
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 derivatives —
 —
 —
 (4,774) —
 (4,774)
Interest expense, net —
 —
 —
 (30,225) —
 (30,225)
Other —
 —
 —
 (11) —
 (11)
Income (loss) before income taxes $(143,017) $(10,667) $4,275
 $(61,057) $—
 $(210,466)
Condensed Consolidating Statements of Operations (Unaudited)
Predecessor
Three Months Ended March 31, 2020
ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Revenues$0 $85,154 $42,680 $(5,458)$122,376 
Expenses:
Operating costs0 56,864 32,317 (5,458)83,723 
Depreciation, depletion, and amortization871 48,473 12,273 0 61,617 
Impairments0 677,962 63,962 0 741,924 
Loss on abandonment of assets0 17,554 0 0 17,554 
General and administrative0 11,553 0 0 11,553 
(Gain) loss on disposition of assets0 396 (6)0 390 
Total operating costs871 812,802 108,546 (5,458)916,761 
Loss from operations(871)(727,648)(65,866)0 (794,385)
Interest, net(12,739)0 (518)0 (13,257)
Gain on derivatives483 0 0 0 483 
Other, net7 35 18 0 60 
Loss before income taxes(13,120)(727,613)(66,366)0 (807,099)
Income tax benefit0 (3,425)0 0 (3,425)
Equity in net earnings from investment in subsidiaries, net of taxes(790,554)0 0 790,554 0 
Net loss(803,674)(724,188)(66,366)790,554 (803,674)
Less: net loss attributable to non-controlling interest(33,180)0 (33,180)33,180 (33,180)
Net loss attributable to Unit Corporation$(770,494)$(724,188)$(33,186)$757,374 $(770,494)
_______________________
(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.
    



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Condensed Consolidating Statements of Cash Flows (Unaudited)
Predecessor
Three Months Ended March 31, 2020
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities$(66,578)$86,663 $9,827 $0 $29,912 
INVESTING ACTIVITIES:
Capital expenditures(421)(13,051)(4,056)0 (17,528)
Producing properties and other acquisitions0 (210)0 0 (210)
Proceeds from disposition of assets0 1,700 51 0 1,751 
Net cash used in investing activities(421)(11,561)(4,005)0 (15,987)
FINANCING ACTIVITIES:
Borrowings under credit agreement39,300 0 32,100 0 71,400 
Payments under credit agreement(23,500)0 (11,600)0 (35,100)
Intercompany borrowings (advances), net75,016 (75,089)73 0 0 
Net payments on finance leases0 0 (1,026)0 (1,026)
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 activities83,504 (75,089)18,083 0 26,498 
Net increase in cash and cash equivalents16,505 13 23,905 0 40,423 
Cash and cash equivalents, beginning of period503 68 0 0 571 
Cash and cash equivalents, end of period$17,008 $81 $23,905 $0 $40,994 


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


Management’s Discussion and Analysis (MD&A) provides you
Introduction

The following discussion should be read together 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 following sections:

General;
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 with your review of the information below as well as our unaudited condensed consolidated financial statements and related notes.

Unless otherwise indicated or required by the content, when usedincluded in Item 1 of Part I of this report and in Item 8 of our 2020 Form 10-K filed with the terms “company,” “Unit,” “us,” “our,” “we,” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries.SEC on March 31, 2021.


General

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


•Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company.UPC. This segment explores, develops, acquires, and produces oil and natural gas properties for our own account.
•Contract Drilling – carried out by our subsidiary Unit Drilling Company.UDC. This segment contracts to drill onshore oil and natural gas wells for others and for our oil and natural gas segment.
•Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas and NGLs for third parties and for our own account. We presently own 50% of this subsidiary.

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

Our strategy is focused on value accretion through generation of free cash flows, repayment of debt, and selective investment in each business segment.

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


In our contract drilling segment, we are focused on utilization of our BOSS drilling rigs. We also plan to continue seeking opportunities to divest non-core, idle drilling equipment.
Business Outlook

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

Upon our emergence from the Chapter 11 Cases on September 3, 2020, we adopted fresh start accounting as required by US GAAP. As discussed in other partsa result of this report,the application of fresh start accounting, as well as the effects of the implementation of the Plan, our consolidated financial statements after August 31, 2020 are not comparable with our consolidated financial statements prior to that date. References to "Successor Period" relate to the results of operations for the period January 1, 2021 through March 31, 2021 and references to "Predecessor Period" refer to the results of operations for the period January 1, 2020 through March 31, 2020.

Recent Developments

COVID-19 Pandemic and Commodity Price Environment

Our success depends, to a large degree,among other things, 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.


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

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During the last two years commodity prices worldwide during the past several years brought about significant and adverse changes to our industry and us. As a result we reduced or stopped, for a period of time, our oil and natural gas segment's drilling activity. Industry wide reductions in drilling activity and spending for extended periods also tends to reduce the rates forhave been volatile, and the number of our drilling rigs that we can work. In addition, sustained lower commodity prices impact 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 fourth quarter of 2016, our oil and natural gas segment began using two of our drilling rigs and has been using two to three of them during the first nine months of 2017. Our contract drilling segment completed the construction and contracted the ninth and tenth BOSS drilling rigs in the fourth quarter of 2016 and the second quarter of 2017, respectively. Our drilling rig segment's rig utilization increased from 16 drilling rigs working as of June 30, 2016, to 33 drilling rigs working as of September 30, 2017. The extent and duration of this improvement remains uncertain.


The reduction in oil, NGLs, and natural gas prices had a number of consequencesoutlook 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 million ($100.6 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, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oilprices remains uncertain 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 adjust the 12-month average price to an estimated fourth quarter ending average (holding October 2017 prices constant for the remaining two months of the fourth quarter of 2017), 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 impact the 12-month average price resulting in the potential for 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.
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

Third quarter2017 production from our oil and natural gas segment was 4,057,000 barrels of oil equivalent (Boe), an increase of 5% over the second quarter of 2017 and a decrease of 3% from the third quarter of 2016, respectively. The increase over the second quarter of 2017 was from acquired wells and new wells drilled in the first nine months of 2017. The decrease from the third 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 2017 oil and natural gas revenues increased 3% over the second quarter of 2017 and increased 8% over the third quarter of 2016. The increase over the second quarter of 2017 was due primarily to higher oil and NGL prices and higher

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 third quarter of 2017 increased 1% over the second quarter of 2017 and increased 11% over the third quarter of 2016. Our NGLs prices increased 23% over the second quarter of 2017 and increased 45% over the third quarter of 2016. Our natural gas prices decreased 4% from the second quarter of 2017 and increased 3% over the third quarter of 2016.

Operating cost per Boe produced for the third quarter of 2017 decreased 2% from the second quarter of 2017 and increased 35% over the third quarter of 2016. The decrease from the second quarter of 2017 was 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 taxes partially offset by lower salt water disposal expense.

At September 30, 2017, we had these derivatives outstanding:
TermCommodityContracted Volume
Weighted Average 
Fixed Price
Contracted Market
Oct'17Natural gas – swap70,000 MMBtu/day$3.038IF – NYMEX (HH)
Nov’17 – Dec'17Natural gas – swap60,000 MMBtu/day$2.960IF – NYMEX (HH)
Jan’18 – Dec'18Natural gas – swap20,000 MMBtu/day$3.013IF – NYMEX (HH)
Nov’17 – Dec'17Natural gas – basis swap20,000 MMBtu/day$(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 collar15,000 MMBtu/day$2.50 - $2.00 - $3.32IF – NYMEX (HH)
Nov’17 – Dec'17Natural 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 collar3,750 Bbl/day$49.79 - $39.58 - $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.

For the nine months ended September 30, 2017, we completed drilling 43 gross wells (15.10 net wells). For all of 2017, we plan to participate in the drilling of approximately 60 to 65 gross wells.Excluding acquisitions and ARO liability, 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.

Contract Drilling

The average number of drilling rigs we operatedfollowing chart reflects the significant fluctuations in the third quarter of 2017 was 34.6 compared to 28.8 and 16.0 in the second quarter of 2017 and the third quarter of 2016, respectively. As of September 30, 2017, 33 of our drilling rigs were operating.

Revenue for the third quarter of 2017 increased 31% and 100% over the second quarter of 2017 and the third quarter of 2016, respectively. The increase over 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 2017 averaged $16,454, a 3% increase over the second quarter of 2017 and a 6% decrease from the third quarter of 2016. The increase over the second quarter of 2017 was 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.

Operating costs for the third quarter of 2017 increased 28% over the second quarter of 2017 and increased 82% over the third quarter of 2016. The increases were due primarily to more drilling rigs operating.

Almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The improved commodity pricinghistorical prices for oil and natural gasgas:

unt-20210331_g2.jpg
The following chart reflects the significant fluctuations in the prices for NGLs:

unt-20210331_g3.jpg_________________________
1.NGLs prices reflect a weighted-average, based on production, of Mont Belvieu and Conway prices.

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Warrants

Each holder of the Old Common Stock outstanding before the Effective Date that began duringdid not opt out of the second halfrelease under the Plan, is entitled to receive its pro rata share of 2016 has increased demand for drilling rigs. Our drilling rig count bottomedseven-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. The Warrants expire on the earliest of (i) September 3, 2027, (ii) consummation of a Cash Sale (as defined in the Warrant Agreement) or (iii) the consummation of a liquidation, dissolutions or winding up of the company (such earliest date, the Expiration Date). Each Warrant that is not exercised on or before the Expiration Date will expire, and all rights under that Warrant and the Warrant Agreement will cease on the Expiration Date. On February 11, 2021, we issued 42,511 Warrants to certain holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares through direct registration with the company’s transfer agent (Direct Registration). We expect to issue approximately 37,000 additional Warrants to the holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares through Direct Registration. Under the Plan, additional Warrants will be issued in book-entry form through the facilities of the DTC, and each holder owning shares of Old Common Stock through Direct Registration must provide that holder’s brokerage account information to the company to receive such holder’s distribution of Warrants. Holders of shares of the Old Common Stock that owned shares through Direct Registration should contact Prime Clerk, LLC at 13 drilling rigs operating during(877) 720-6581 (Toll Free) or (646) 979-4412 (Local) to obtain the second quarter of 2016, but increasedforms necessary to 21 drilling rigs operatingreceive their distribution. Any distribution not made will be deemed forfeited 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 nine term drilling contracts with original terms ranging from six months to two years. Four 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. 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 with signed term contracts opted to release the drilling rig and pay an early termination penalty for the remaining termanniversary of the contract. During the first nine months of 2017, we recorded $0.8 million of early termination fees compared to $3.1 million in the first nine months of 2016.Effective Date.


All ten of our 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 capital expenditures for this segment are approximately $38.0 million.

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

Third quarter 2017 liquids sold per day increased 1% over the second quarter of 2017 and decreased 5% from the third quarter of 2016, respectively. The increase over the second quarter of 2017 was due to increased volumes available to our processing facilities. The decrease from the third quarter of 2016 was primarily due to less volume available to process at our plants. For the third quarter of 2017, gas processed per day increased 4% over the second quarter of 2017 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% from the second quarter of 2017 and the third quarter of 2016, respectively. The decrease from the third quarter of 2016 was primarily due to declining gathered volume on our Appalachian gathering systems.

NGLs prices in the third quarter of 2017 increased 27% over the prices received in the second quarter of 2017 and increased 53% over the prices received in the third quarter of 2016. Because certain of the contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts–under which we receive a share of the proceeds from the sale of the NGLs–our revenues from those commodity-based contracts fluctuate based on the price of NGLs.

Total operating cost for our mid-stream segment for the third quarter of 2017 increased 6% over the second quarter of 2017 and increased 7% over the third quarter of 2016. Third quarter of 2017 costs were higher than the second quarter of 2017 primarily due to both increased purchase volumes and prices and increased field direct operating expenses. The increase over 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.

In the Appalachian region, our Pittsburgh Mills gathering system, in Allegheny and Butler counties, continues to produce consistent financial results. Our average gathered volume for the third quarter of 2017 is approximately 128.5 MMcf per day.

We connected the new Allen well pad in May and it included five new wells. 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 our system in the second half of 2018.

At our Hemphill Texas system, our total throughput volume averaged 60.8 MMcf per day for the third quarter of 2017 and our total production of natural gas liquids was approximately 164,000 gallons per day. During the third quarter, we connected two new wells and since the beginning of 2017, we connected four new wells to this processing facility. Our oil and gas segment continues to operate a rig and we 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 four new wells to this system in the third quarter for a total of six new 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 2017 capital expenditures for this segment are approximately $18.9 million.

Financial Condition and Liquidity


Summary


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

•the amount of natural gas, oil, and NGLs we produce;
•the prices we receive for our natural gas, oil, and NGLs production;
•the demand foruse of our drilling rigs and the dayratesrates we receive for ourthose drilling rigs; and
•the fees and margins we obtain from our natural gas gathering and processing contracts.


We believe we will have enoughcurrently expect that cash flow and liquidity to meet our obligationscash equivalents, cash generated from operations, and remain in compliance with our debt covenants foravailable funds under the next twelve months. Our ability to meet our debt covenants (under ourExit 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 ourSuperior credit agreement it could cause a reduction of the borrowing base and therefore reduce or limit our abilityare adequate to incur indebtedness. We monitorcover our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues, and work, where possible, with our lenders to address those issues aheadrequirements for at least the next 12 months.

Below is a summary of time.certain financial information for the periods indicated:
 SuccessorPredecessor%
Change
 Three Months Ended March 31, 2021Three Months Ended March 31, 2020
 (In thousands except percentages)
Net cash provided by operating activities30,304 29,912 1 %
Net cash provided by (used in) investing activities2,428 (15,987)115 %
Net cash provided by (used in) financing activities(20,258)26,498 (176)%
Net increase in cash, restricted cash and cash equivalents$12,474 $40,423 


  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,NGL, and natural gas we produce, settlements of derivative contracts, and third-party demanduse for our drilling rigs and mid-stream services, and the rates we obtaincan charge 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 ninethree months of 2017 decreased2021 increased by $13.0$0.4 million as compared to the first ninethree months of 2016.2020. The decrease was the result ofincrease resulted from increased operating profit in all three segments partially offset by changes in operating assets and liabilities related to the timing of cash receipts and disbursements partially offset by higher profit margins in all three segments.disbursements.

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Cash Flows from Investing Activities


We dedicate and expect to continue to dedicatehave historically dedicated a substantial portion of our capital budgetbudgets to theour exploration for and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells. Although we have curtailed our spending throughout 2020 and into 2021, we expect any future capital budgets would be focused on development or acquisitions of producing oil and gas properties, and not exploration.


Cash flows used inNet cash provided by (used in) investing activities increaseddecreased by $96.7$18.4 million for the first ninethree months of 20172021 compared to the first ninethree months of 2016.2020. The change was due primarily to an increasea decrease in capital expenditures due to anresulting from a decrease in number of wells drilled, along with a decrease in oil and gas property acquisition, the restarting of our drilling programacquisitions, which was partially offset by an increase in 2017, the construction of two new BOSS drilling rigs, and a decrease in the proceeds received from the disposition of assets. See additional information on capital expenditures below under Capital Requirements.


Cash Flows from Financing Activities


Cash flowsNet cash provided by (used in) financing activities increaseddecreased by $109.5$46.8 million for the first ninethree months of 20172021 compared to the first ninethree months of 2016.2020. The increasedecrease was primarily due to proceeds fromdecreases in both the ATM common stock programnet borrowings under our credit agreements and an increase in book overdrafts in 2017 coupled with almost no change in net borrowing after paying down long-term debt in 2016.bank overdrafts.


At September 30, 2017,March 31, 2021, we had unrestricted cash and cash equivalents totaling $0.8$25.2 million and had borrowed $162.1$79.0 million of the $475.0 million we had elected to then haveamounts available under ourthe Exit credit agreement. OurWe did not have any outstanding borrowings under our Superior credit agreement is used primarily for working capital and capital expenditures.agreement.


The following is a summary ofBelow, we summarize certain financial information as of September 30, 2017March 31:
SuccessorPredecessor
 20212020
 (In thousands)
Working capital$6,096 $(781,278)
Current portion of long-term debt (1)
$800 $771,283 
Long-term debt$78,200 $37,000 
Shareholders’ equity attributable to Unit Corporation$177,359 $85,878 
_________________________
1.Current portion of long-term debt is net of unamortized discount and 2016 anddebt issuance costs for the nine months ended September 30, 2017 and 2016:Predecessor Period.

  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 %



Working Capital


Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative activity. We had positive working capital of $6.1 million and negative working capital of $62.2 million and $42.3$781.3 million as of September 30, 2017March 31, 2021 and 2016,2020, respectively. The increase in negative working capital is primarily due to increasedthe settlement of the liabilities subject to compromise, an increase in accounts receivable and lower accounts payable and accrued liabilities. At March 31, 2020, the negative working capital was primarily due to increased activity in our drilling program and increased drilling rig utilizationthe springing maturity of the Unit credit agreement and the reclassification of current deferred tax asset to long-term asset per ASU 2015-17 partially offset by increased accounts receivable from increased revenuesNotes and the change indetermination to treat the value of outstanding derivatives. Ourborrowings as current liabilities. Both the Superior credit agreement isand the Exit credit agreement are used primarily for working capital and capital expenditures. At September 30, 2017, we had borrowed $162.1 million of the $475.0 million available under our credit agreement.capital. The effect of our derivative contracts decreased working capital by $14.0 million as of March 31, 2021 and increased working capital by $0.4$0.7 million as of September 30, 2017March 31, 2020.

Our Credit Agreements

Exit Credit Agreement. On the Effective Date, under the terms of the Plan, the company entered into an amended and decreased working capital by $5.6restated credit agreement (the Exit credit agreement), providing for a $140.0 million senior secured revolving credit facility (RBL Facility) and a $40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC (together, the Borrowers), (ii) the guarantors party thereto, including the company and all of its subsidiaries existing as of September 30, 2016.

The following table summarizes certain operating information:
  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)%

Oilthe Effective Date (other than Superior Pipeline Company, L.L.C. and Natural Gas Operations

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

Based on our first nine months of 2017 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 per month ($4.8 million annualized) change in our pre-tax operating cash flow. The average price we received for our natural gas production, including the effect of derivatives, during the first nine months of 2017 was $2.50 compared to $1.98 for the first nine months of 2016. Based on our first nine months of 2017 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $212,000 per month ($2.5 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 per month ($4.5 million annualized) change in our pre-

tax operating cash flow. In the first nine months of 2017, our average oil price per barrel received, including the effect of derivatives, was $47.62 compared with an average oil price, including the effect of derivatives, of $38.71 in the first nine months of 2016 and our first nine months of 2017 average NGLs price per barrel received was $17.05 compared with an average NGLs price per barrel of $10.16 in the first nine months of 2016.

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. At September 30, 2017, the 12-month average unescalated prices were $49.81 per barrel of oil, $27.70 per barrel of NGLs, and $3.00 per Mcf of natural gas, and then are adjusted for price differentials. We did not have to take a write down in the first nine months 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 adjust the 12-month average price to an estimated fourth quarter ending average (holding October 2017 prices constant for the remaining two months of the fourth quarter of 2017), 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.

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

Contract Drilling Operations

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

Most of our working drilling rigs 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. 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 affect our future dayrates. For the first nine months of 2017, our average dayrate was $16,120 per day compared to $18,147 per day for the first nine months of 2016. The average number of our drilling rigs used in the first nine months of 2017 was 29.7 drilling rigs compared with 16.7 drilling rigs in the first nine months of 2016. Based on the average utilization of our drilling rigs during the first nine months of 2017, a $100 per day change in dayrates has a $2,970 per day ($1.1 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, 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 million for the first nine months of 2017 from our contract drilling segment and eliminated the associated operating expense of $8.6 million yielding $1.0 million as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue in our contract drilling segment for the first nine months of 2016.

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, 13 processing plants, 25 gathering systems, and approximately 1,480 miles of pipeline. It operates in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. Besides serving third parties, this segment also enhances our ability to gather and market our own natural gas and NGLs and serving as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first nine months of 2017 and 2016, our mid-stream operations purchased $43.2 million and $28.5 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $4.9 million and $7.4 million, respectively. Intercompany revenue from services and purchases of production between this business segment and our oil and natural gas segment has been eliminated in our unaudited condensed consolidated financial statements.

This segment gathered an average of 385,846 Mcf per day in the first nine months of 2017 compared to 417,722 Mcf per day in the first nine months of 2016. It processed an average of 133,986 Mcf per day in the first nine months of 2017 compared to 160,411 Mcf per day in the first nine months of 2016. The amount of NGLs sold was 518,054 gallons per day in the first nine months of 2017 compared to 536,911 gallons per day in the first nine months of 2016. Gas gathered volumes per day in the first nine months of 2017 decreased 8% compared to the first nine months of 2016 primarily due to declines in existing volumes, fewer new wells connected, and no offload volume at our Hemphill facility in 2017. Gas processed volumes for the first nine months of 2017 decreased 16% from the first nine months of 2016 due to declines in existing volumes, fewer new wells connected to our 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,lenders party thereto from time to time through(Lenders), and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (in such capacity, the sales agent sharesAdministrative Agent). The maturity date of our common stock, par value $0.20 per share (the Shares), up to an aggregate offering priceborrowings under this Exit credit agreement is March 1, 2024.

34
Table of $100.0 million. We intend to useContents
Our Exit credit agreement is primarily used for working capital purposes as it limits the net proceeds from these sales to fund (or offset costs of) acquisitions,amount that can be borrowed for capital expenditures. These limitations restrict future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
Underprojects using 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 directly 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 terms 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 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 we may impose).
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 Agreement and Senior Subordinated Notes

Credit Agreement. Our Senior Credit Agreement (credit agreement) is scheduled to mature on April 10, 2020. Under the credit agreement, the amount we can borrow 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% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of theExit credit agreement. Under the credit agreement, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our mid-stream affiliate, Superior Pipeline Company, L.L.C.


The current lenders under our credit agreement and their respective participation interests are:
Lender
Participation
Interest
BOK (BOKF, NA, dba Bank of Oklahoma)17%
Compass Bank17%
BMO Harris Financing, Inc.15%
Bank of America, N.A.15%
Comerica Bank8%
Wells Fargo Bank, N.A.8%
Canadian Imperial Bank of Commerce8%
Toronto Dominion (New York), LLC8%
The Bank of Nova Scotia4%
100%

The borrowing base amount–which is subject to redetermination by 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 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.

TheExit credit agreement also requires that proceeds from the disposition of certain assets be used to repay amounts outstanding.

At March 31, 2021, we have athad $0.8 million and $78.2 million outstanding current and long-term borrowings, respectively, under the endExit credit agreement. During the period ended March 31, 2021, the company repaid $20.0 million of each quarter:borrowings under the RBL Facility with cash generated from operations as well as from proceeds from divestitures of non-core assets.


On April 6, 2021, the company finalized the first amendment to the Exit credit agreement. Under the first amendment, the company reaffirmed its borrowing base of $140.0 million of the RBL, amended certain financial covenants, and received less restrictive terms as it relates to the disposition of assets and the use of proceeds from those dispositions.

Superior Credit Agreement. On May 10, 2018, Superior signed a current ratio (as defined infive-year, $200.0 million senior secured revolving credit facility with an option to increase the credit agreement) of not less than 1amount up 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, we were in compliance with the credit agreement covenants.

6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0$250.0 million, 6.625% senior subordinated notes (the Notes) outstanding. Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes mature on May 15, 2021. In issuing the Notes, we incurred fees of $14.7 million that are being amortized as debt issuance cost over the life of the Notes.

The Notes are 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), 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 discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.

Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes
(registered under registration statements) are 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. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of our subsidiaries through dividends, loans, advances, or otherwise.

We may redeem all or, occasionally, a part 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 repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the(Superior credit agreement). The maturity date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that limit our abilityborrowings under the Superior credit agreement is March 10, 2023. During the period ended March 31, 2021, the company did not utilize the Superior credit facility 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.had no borrowings outstanding.


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. 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 one gross wells (15.10well (0.17 net wells) drilled by other operators in the first ninethree months of 20172021 compared to 1514 gross wells (7.77(3.07 net wells) drilled by Unit and other operators in which we participated in the first ninethree months of 2016.2020.

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 ninethree months of 20172021 by this segment, excluding $56.4 million for acquisitions and a $2.8 million in the ARO liability, totaled $143.7$2.6 million. Capital expenditures for the first ninethree months of 2016,2020, excluding $0.2 million for acquisitions and a $29.4$3.4 million reduction in the ARO liability, totaled $91.9$7.7 million.


For 2021, we primarily plan to focus our capital expenditures on development of proved properties and acquisition of proved and producing properties.

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

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. Whether we can drill the full numbersold $1.7 million 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 fornon-core oil NGLs, and natural gas demand for oil, NGLs, and natural gas,assets, net of related expenses, during the first three months of 2021, compared to $0.6 million during the first three months of 2020. These proceeds reduced the net book value of our full cost to drill wells, the weather, and the efforts of outside industry partners.pool with no gain or loss recognized.


Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. DuringFor 2021, capital expenditures are expected to primarily be for maintenance capital on operating drilling rigs. We also plan to pursue the first quarterdisposal or sale of 2017, we were awarded a term contract to build our tenth BOSS rig. Construction was completed and thenon-core, idle drilling rig was placed into service late in the second quarter.

Our estimated 2017 capital expenditures 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.fleet. We have spent $30.0$0.1 million for capital expenditures during the first ninethree months of 2017,2021, compared to $7.2$2.2 million for capital expenditures during the first ninethree months of 2016.2020.


Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. In the Appalachian region, our Pittsburgh Mills gathering system, in Allegheny and Butler counties, continues to produce consistent financial results. Our average gathered volume for the third quarter of 2017 is approximately 128.5 MMcf per day. We connected the new Allen well pad in May and it included five new wells. 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 our system in the second half of 2018.

At our Hemphill Texas system, our total throughput volume averaged 60.8 MMcf per day for the third quarter of 2017 and our total production of natural gas liquids was approximately 164,000 gallons per day. During the third quarter, we connected two new wells and since the beginning of 2017, we connected four new wells to this processing facility. Our oil and gas segment continues to operate a rig and we 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 four new wells to this system in the third quarter for a total of six new 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 ninethree months of 2017,2021, our mid-stream segment incurred $10.1$1.1 million in capital expenditures as compared to $11.1$5.0 million in the first ninethree months of 2016.2020. For 2017,2021, our estimated capital expenditures arewill be approximately $18.9 million.$15.0 million which we expect to be primarily for the maintenance and operation of our assets and connection of new wells.



Contractual Commitments

At September 30, 2017, 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.



At September 30, 2017, we also had the following commitments and contingencies that could create, increase, or accelerate our liabilities:
  Estimated Amount of Commitment Expiration Per Period
Other Commitments 
Total
Accrued
 
Less
Than 1
Year
 
2-3
Years
 
4-5
Years
 
After 5
Years
  (In thousands)
Deferred compensation plan (1)
 $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.

(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).

(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.

(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.

Derivative Activities


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

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Commodity Derivatives. Our commodity derivatives are intended to reduce our exposure to price volatility and manage price risks. Our decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our view of current and future market conditions. At September 30, 2017,March 31, 2021, based on our thirdfirst quarter 20172021 average daily production, the approximated percentages of our production under derivative contracts are as follows:
202120222023
Daily oil production74 %51 %29 %
Daily natural gas production61 %50 %27 %

  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 September 30, 2017March 31, 2021 evaluation, we believe the risk of non-performance by our counterparties is not material. At September 30, 2017,March 31, 2021, the fair values of the net assets (liabilities)liabilities we had with each of the counterparties to our commodity derivative transactions are as follows:
March 31, 2021
(In thousands)
Bank of Oklahoma$(24,857)
Bank of Montreal(376)
Total net liabilities$(25,233)
  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 rightBelow is the effect of set-off exists, we netderivative instruments on the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets. At September 30, 2017, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $1.0 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.

For our economic hedges any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations. These gains (losses) at September 30 are as follows:
  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 nine months of 2017, we granted awards covering 698,276 shares of restricted stock. These awards had an estimated fair value as of their grant date of $17.2 million. Compensation expense will be recognized over the three year vesting periods, and during the nine months of 2017, we recognized $5.0 million in compensation expense and capitalized $0.8 million for these awards. During the first nine months of 2017, we recognized compensation expense of $9.0 million for all of

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

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 are the general partner of 13 oil and natural gas partnerships which were formed privately or publicly. Each partnership’s revenues and costs are shared under formulas set out in that partnership’s agreement. The partnerships repay us for contract drilling, well supervision, and general and administrative expense. Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed on the same basis as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party’s behalf as well as indirect expenses assigned to the related parties. Allocations are based on the related party’s level of activity and are 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) relating to the oil and natural gas partnerships is included in our unaudited condensed consolidated financial statements.

New Accounting Pronouncements

Compensation—Stock Compensation. The FASB issued ASU 2017-09, to clarify 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. The amendments are 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 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 assetOperations for the lease term. Lessorperiods indicated:
SuccessorPredecessor
Three Months Ended March 31, 2021Three Months Ended March 31, 2020
 (In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $(3,304) and $551, respectively$(22,831)$483 
$(22,831)$483 


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
36
Table of mineral rights. We are in the process of evaluating the impact these amendments will have on our financial statements.Contents

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. The 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 financial statements.


Results of Operations
QuarterThree Months Ended September 30, 2017 March 31, 2021 versus QuarterThree Months Ended September 30, 2016 March 31, 2020
Provided below is a comparison of selected operating and financial data:
 SuccessorPredecessor
Percent
Change (1)
 Three Months Ended March 31, 2021Three Months Ended March 31, 2020
(In thousands unless otherwise specified)
Total revenue$120,897 $122,376 (1)%
Net loss$(591)$(803,674)100 %
Net income (loss) attributable to non-controlling interest$1,346 $(33,180)104 %
Net loss attributable to Unit Corporation$(1,937)$(770,494)100 %
Oil and Natural Gas:
Revenue$55,024 $48,522 13 %
Operating costs$19,149 $30,663 (38)%
Average oil price (Bbl)$47.29 $44.92 5 %
Average oil price per barrel received excluding derivatives$56.12 $44.92 25 %
Average NGLs price (Bbl)$17.96 $3.27 NM
Average NGLs price per barrel received excluding derivatives$17.96 $3.27 NM
Average natural gas price (Mcf)$2.77 $1.23 125 %
Average natural gas price per mcf received excluding derivatives$2.72 $1.18 131 %
Oil production (MBbls)413 674 (39)%
NGLs production (MBbls)641 965 (34)%
Natural gas production (MMcf)7,403 10,802 (31)%
Contract Drilling:
Revenue$15,674 $36,632 (57)%
Operating costs$11,871 25,449 (53)%
Average number of drilling rigs in use9.4 18.7 (50)%
Total drilling rigs available for use at the end of the period21 58 (64)%
Average dayrate on daywork contracts$18,127 $19,535 (7)%
Mid-Stream:
Revenue$50,199 $37,222 35 %
Operating costs$40,543 $27,611 47 %
Gas gathered--Mcf/day299,591 389,243 (23)%
Gas processed--Mcf/day121,138 166,331 (27)%
Gas liquids sold--gallons/day409,285 527,673 (22)%
Number of natural gas gathering systems17 19 (11)%
Number of processing plants11 11 — %
Corporate and Other:
General and administrative expense$6,289 $11,553 (46)%
Other income (expense):
Interest expense, net$(2,706)$(13,257)(80)%
Reorganization costs, net$(1,136)$— — %
Gain (loss) on derivatives$(22,831)$483 NM
Income tax benefit$— $(3,425)100 %
Average interest rate6.8 %6.3 %8 %
Average long-term debt outstanding$93,227 $761,502 (88)%
_________________________
1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
  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 %
37
_________________________
(1)NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

Table of Contents

Oil and Natural Gas


Oil and natural gas revenues increased $6.6$6.5 million or 8%13% in the third quarterfirst three months of 20172021 as compared to the third quarterfirst three months of 20162020 primarily due to higher commodity prices partially offset from reducedby lower volumes. The decline in volumes was due to normal well production volumes. In the third quarter of 2017, as compared to the third quarter of 2016, oil production decreased 10%, natural gas production decreased 2%, and NGLs production decreased 1%. Average oil prices increased 11% to $47.29 per barrel, average natural gas prices increased 3% to $2.36 per Mcf, and NGLs prices increased 45% to $18.35 per barrel.declines which have not been offset by new drilling or acquisitions for new production.


Oil and natural gas operating costs increased $7.9decreased $11.5 million or 30%38% between the comparative third quartersfirst three months of 20172021 and 20162020 primarily due to higherlower LOE, and gross production taxes partially offset by lower saltwaterhigher salt water disposal expenses.operating expense.


Depreciation, depletion, and amortization (“DD&A”)Contract Drilling

Drilling revenues decreased $0.7$21.0 million or 2% due primarily to a 3% decrease in equivalent production partially offset by a 2% increase in the DD&A rate. The increase in our DD&A rate in the third quarter of 2017 compared to the third quarter of 2016 resulted primarily from the cost of wells drilled57% in the first ninethree months of 2017.

During the third quarter of 2016, we recorded a non-cash ceiling test write-down of $49.4 million pre-tax ($30.8 million, net of tax). We did not have a write-down for the third quarter of 2017.

Contract Drilling

Drilling revenues increased $25.8 million or 100% in the third quarter of 20172021 versus the third quarterfirst three months of 2016.2020. The increasedecrease was due primarily to a 116% increase50% decrease in the average number of drilling rigs in use partially offset byand a 6%7% decrease in the average dayrate. Average drilling rig utilization increaseddecreased from 16.018.7 drilling rigs in the third quarterfirst three months of 20162020 to 34.69.4 drilling rigs in the third quarterfirst three months of 2017.2021. The decline in our average drilling rig utilization is a result of the impact of reduced commodity prices.


Drilling operating costs increased $15.6decreased $13.6 million or 82%53% between the comparative third quartersfirst three months of 20172021 and 2016.2020. The increasedecrease was due primarily to more drilling rigs operating. Contract drilling depreciation increased $4.0 million or 35% also due primarily to moreless drilling rigs operating.


During the period, management reduced the number of drilling rigs available for use to 21 compared to 58 at December 31, 2020. The decrease corresponds with the company's strategy to focus on the utilization of our 14 BOSS rigs and certain SCR rigs that are either currently under contract or candidates for future upgrades. Of the 21 rigs available for use, 10 are currently working, seven are actively being marketed, and the remaining four will be considered for upgrade and marketing as future conditions warrant. The company will continue its efforts to sell or scrap those other rigs that are not considered part of our available fleet.

Mid-Stream


Our mid-stream revenues increased $2.7$13.0 million or 5%35% in the third quarterfirst three months of 20172021 as compared to the third quarterfirst three months of 20162020 due primarily to increases in NGLs and condensate prices.higher prices partially offset by lower volumes. Gas processed volumes per day decreased 8%27% between the comparative quartersperiods primarily due to declines in existingdeclining volumes, lower offload volume from producers, and fewer new wells connected to our processing systems, and no offload volume at our Hemphill facility in 2017.producing systems. We also experienced lower volumes due to the February winter storm. Gas gathered volumes per day decreased 11%23% between the comparative quarters primarilyperiods also due to declining gathered volumes, onlower offload volume from producers, and fewer new wells connected to our Appalachianproducing systems.


Operating costs increased $2.4$12.9 million or 7%47% in the third quarterfirst three months of 20172021 compared to the third quarterfirst three months of 20162020 primarily due to 26% higher gas purchase prices partially offset by a 9% decrease inlower purchase volumes. Depreciation and amortization decreased $0.6 million, or 5%, primarily due to certain assets being fully depreciated 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.


General and Administrative


Corporate general and administrative expenses increased $0.4decreased $5.3 million or 4%46% in the third quarterfirst three months of 20172021 as compared to the third quarterfirst three months of 20162020 primarily due to an increase inlower consulting and legal fees paid prior to filing for bankruptcy as well as reduced employee costs.headcount.


Other Income (Expense)


Interest expense net of capitalized interest, decreased $0.1$10.6 million between the comparative third quartersfirst three months of 20172021 and 20162020 due primarily to a 7% decrease in average long-term debt outstanding in the third quarter of 2017 and an increase in 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 interest for the third quarter of 2017 was $4.0 million compared to $3.6 million in the third quarter of 2016, and was netted against our gross interest of $14.0 million and $13.6 million for the third quarters of 2017 and

2016, respectively.reduced borrowings. Our average interest rate increased from 5.7%6.3% in the third quarterfirst three months of 20162020 to 6.0%6.8% in the third quarterfirst three months of 20172021 and our average debt outstanding was $61.6decreased $668.3 million lower in the third quarterfirst three months of 2017 as2021 compared to the third quarterfirst three months of 20162020 primarily due to the decrease in outstanding borrowings under our credit agreement overNotes being settled with the comparative periods.Plan.


Reorganization Items, Net

Reorganization items, net represent any of the expenses, gains, and losses incurred subsequent to and as a direct result of the Chapter 11 proceedings.

38
Table of Contents
Gain (Loss) on Derivatives


Gain (loss) on derivatives increased $9.6decreased by $23.3 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.


Income Tax Expense (Benefit)Benefit


IncomeWe did not record an income tax expense increased $16.4benefit in the first three months of 2021 compared to $3.4 million betweenin the comparative third quartersfirst three months of 2017 and 2016 primarily2020 due to increased pre-tax income.the company's full valuation allowance against our net deferred tax asset. Our effective tax rate was 32.3%0.00% for the third quarterfirst three months of 20172021 compared to 37.8%0.42% for the third quarterfirst three months of 2016. The rate change was primarily2020 due to the recognition ofadjustment to our Uncertain Tax Position associated with a research and development tax credit of $0.4 million. There was no currenttotal valuation allowance for the income tax expense or benefit in the third 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 partially 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). 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 implementedgenerated 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.period. 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 interest for the first nine 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 waspaid 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 ninethree months of 2017.2021.


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 meaning 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.

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 ninethree months 20172021 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$250,000 per month ($4.83.0 million annualized)

change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of hedging, would have a $212,000$132,000 per month ($2.51.6 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$209,000 per month ($4.52.5 million annualized) change in our pre-tax operating cash flow.


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


At September 30, 2017, the followingMarch 31, 2021, these derivatives were outstanding:
TermCommodityContracted Volume
Weighted Average 

Fixed Price
Contracted Market
Oct'17Apr'21 - Dec'21Natural gas –- basis swap70,00030,000 MMBtu/day$3.038(0.215)NGPL TEXOK
Apr'21 - Oct'21Natural gas - swap50,000 MMBtu/day$2.818IF –- NYMEX (HH)
Nov’17 – Dec'17Nov'21 - Dec'21Natural gas –- swap60,00045,000 MMBtu/day$2.9602.900IF –- NYMEX (HH)
Jan’18 – Dec'18Jan'22 - Dec'22Natural gas –- swap20,0005,000 MMBtu/day$3.0132.605IF –- NYMEX (HH)
Nov’17 – Dec'17Jan'23 - Dec'23Natural gas – basis- swap20,00022,000 MMBtu/day$(0.215)2.456IF –- NYMEX (HH)
Jan’18 – Mar'18Jan'22 - Dec'22Natural gas – basis swap- collar10,00035,000 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 collar15,000 MMBtu/day$2.50 - $2.00$2.68IF - $3.32IF – NYMEX (HH)
Nov’17 – Dec'17Apr'21 - Dec'21Natural gas – three-way collarCrude oil - swap25,000 MMBtu/3,373 Bbl/day$2.9046.16WTI - $2.30 - $3.59IF – NYMEX (HH)
Jan'18 – Mar'18Jan'22 - Dec'22Natural gas – three-way collarCrude oil - swap60,000 MMBtu/2,300 Bbl/day$3.2942.25WTI - $2.63 - $4.07IF – NYMEX (HH)
Apr'18 – Dec'18Jan'23 - Dec'23Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Oct’17 – Dec'17Crude oil – three-way collar- swap3,7501,300 Bbl/day$49.7943.60WTI - $39.58 - $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.

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our Exit credit agreement and the Notes. TheSuperior credit agreement. Borrowings under our Exit credit agreement at our election bears interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election, borrowings under ourand 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 acarry variable rate in the first nine months of 2017, ainterest rates. A 1% increase in the floating rateinterest rates on the outstanding borrowings under these facilities at March 31, 2021 would reduce our annual pre-tax cash flow by approximately $1.6$0.1 million. Under our Notes, we pay a fixed rateFor further information, see Note 8 – Long-Term Debt and Other Long-Term Liabilities.

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Table of interest of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year).Contents


Item 4. Controls and Procedures


Our management, including our Chief Executive Officer (CEO) and Interim Chief Financial Officer (Interim CFO), does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) (Disclosure Controls) or our internal control over financial reporting (ICFR) (as defined in Rules 13a - 15(f) and 15d - 15(f) of the Exchange Act) will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part on certain assumptions about the likelihood of future events, and there is no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to an error or fraud may occur and not be detected. We monitor our Disclosure Controls and ICFR and make modifications as necessary; our intent in this regard is that the Disclosure Controls and ICFR will be modified as systems change, and conditions warrant.

Evaluation of Disclosure Controls and Procedures.As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive OfficerCEO and Chief Financial Officer,Interim 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 OfficerInterim CFO concluded that our disclosure controls and procedures arewere not effective as of September 30, 2017 in ensuring the appropriate information is recorded, processed, summarized and reported in our periodic SEC filings relatingMarch 31, 2021 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 described below.

Material Weakness in ICFR. A material weakness is a deficiency, or combination of deficiencies, in ICFR resulting in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

As previously disclosed in our Quarterly Report on Form 10-Q for the period ended June 30, 2020, in preparing our interim financial statements for the quarterly period ended June 30, 2020, we determined that a material weakness related to management review controls over complex accounting matters was present. Key elements of effectively designed management review controls include the establishment of documentation standards for process owners to document the substance of their work related to critical accounting estimates, complex accounting matters, and non-routine transactions. Effectively designed management review controls must also have an established process that allows senior accounting personnel having the appropriate knowledge of the subject matter to have enough time to perform effective reviews. Necessary elements for effectively designed management review controls were either not present at June 30, 2020 or not present for a sufficient period of time in order to conclude our disclosure controls and procedures were effective at June 30, 2020. This continued to be the case at March 31, 2021.

Plan for Remediation of the Material Weakness. We continue to address the underlying cause of the material weakness, including a redesign of certain management review controls related to complex accounting matters, the establishment of documentation standards, assessing the structure of the accounting organization, providing additional training for employees responsible for performing important management review controls, and supplementing internal resources with external expertise when appropriate.

We have also hired new personnel in key positions and continue to evaluate the need for additional personnel to further enhance the overall control environment.

Our management believes the measures described above will eventually remediate this material weakness. As management continues to evaluate and improve internal control over financial reporting, (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 September 30, 2017,March 31, 2021, that materially affected our ICFR or are reasonably likely to materially affect it, as defined in Rule 13a – 15(f) under the Exchange Act.


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Table of Contents
PART II. OTHER INFORMATION

Item 1. Legal Proceedings


Panola Independent School District No. 4, et al. v. Unit Petroleum Company, No. CJ-07-215, District Court of Latimer County, Oklahoma.For further information about the outstanding legal proceedings, please see Note 14 – Commitments And Contingencies.


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.

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 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 owners in our Oklahoma wells. We have asserted several defenses including that the case cannot 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.

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, 2016,2020, which could materially affect our business, financial condition, or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, and/or operating results.


Except as set forth below, thereThere have been no material changes to the risk factors disclosed in Item 1A in our Form 10-K for the year ended December 31, 2016.2020.


We are the subject of putative class action lawsuits that may result in substantial expenditures and divert management's attention.

We are the subject 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 of these lawsuits or other matters that may arise from time to time could have a material adverse effect on our business, results of operations and financial condition. Defending the lawsuits may be costly and, further, could require significant involvement of our senior management and may divert management's attention from our business and operations.

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 September 30, 2017:Not Applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.


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Table of Contents
Item 6. Exhibits

Exhibits:
Period10.1
(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, 2017First Amendment to July 31, 2017—
$—
—
—
August 1, 2017 to August 31, 2017—
—
—
—
September 1, 2017 to September 30, 2017—
—
—
—
Total—
$—
—
—
Amended and Restated Credit Agreement dated April 6, 2021

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.


Item 5. Other Information

Not applicable.


Item 6. Exhibits

Exhibits:
31.110.2
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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Table of Contents
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, 2017May 12, 2021
By: /s/ Larry D. PinkstonPhilip B. Smith
LARRY D. PINKSTONPHILIP B. SMITH
President and Chief Executive Officer and Director
Date:November 2, 2017May 12, 2021
By: /s/ David T. MerrillThomas D. Sell
DAVID T. MERRILLTHOMAS D. SELL
Chief Operating Officer,Interim Chief Financial Officer
and Treasurer



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