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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[x]☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20172021
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]1-9260
unt-20210930_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 Section 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 has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒   No ☐    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [  ]☐            No [x]  ☒         
As of October 20, 2017, 52,879,660November 12, 2021, 10,260,037 shares of the issuer'sregistrant's common stock were outstanding.


Table of Contents
TABLE OF CONTENTS
Page
Number
PART I. Financial Information
Item 1.
Page
Number
PART I. Financial Information
Item 1.
Financial Statements (Unaudited)
Unaudited Condensed Consolidated Balance Sheets
September 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.
3041
Item 3.
5453
Item 4.
5654
PART II. Other Information
Item 1.
56
Item 1A.
5756
Item 2.
5756
Item 3.
57
Item 4.
57
Item 5.
5857
Item 6.
5958
6059


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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 addressesaddress 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 and 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;
•our ability, and the market's receptiveness, to execute a strategic divestiture process;
•our ability to retain or recruit key personnel throughout a strategic divestiture process;
•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 drill;
•the year; andeffects of world health events, including the COVID-19 pandemic;
•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;
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•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;
•risks associated with future weather conditions;
•decreases or increases in commodity prices;
putative class action lawsuits that may result•the consequences of any divestitures of assets;
•the amount and terms of our debt;
•future compliance with covenants under our credit agreements;
•our ability to remediate a material weakness in substantial expendituresour internal controls over financial reporting;
•pandemics, epidemics, outbreaks, or other public health events, such as COVID-19;
•our ability to retain and divert management's attention;recruit talent if vaccination mandates or other similar regulation is required; 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 3 "Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk.”

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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30,
2021		December 31,
2020
 (In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents$49,566 $12,145 
Restricted cash— 569 
Accounts receivable, net of allowance for credit losses of $2,573 and $3,783 at September 30, 2021 and December 31, 2020, respectively72,405 57,846 
Current income tax receivable22 1,150 
Prepaid expenses and other6,120 11,212 
Total current assets128,113 82,922 
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties225,786 238,581 
Unproved properties not being amortized247 1,591 
Drilling equipment64,278 63,687 
Gas gathering and processing equipment259,642 251,404 
Land and building— 32,635 
Transportation equipment3,750 3,130 
Other8,892 9,961 
562,595 600,989 
Less accumulated depreciation, depletion, amortization, and impairment103,794 54,189 
Net property and equipment458,801 546,800 
Right of use asset (Note 14)13,800 5,592 
Other assets16,086 14,389 
Total assets (1)
$616,800 $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

September 30,
2021		December 31,
2020
 (In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable$47,106 $37,368 
Accrued liabilities (Note 8)26,979 25,204 
Current operating lease liability (Note 14)4,399 4,075 
Current portion of long-term debt (Note 9)— 600 
Current derivative liabilities (Note 12)59,962 1,047 
Warrant liability (Note 13)13,512 885 
Current portion of other long-term liabilities (Note 9)6,522 11,168 
Total current liabilities158,480 80,347 
Long-term debt (Note 9)3,100 98,400 
Non-current derivative liabilities (Note 12)28,069 4,659 
Operating lease liability (Note 14)9,387 1,445 
Other long-term liabilities (Note 9)41,474 39,259 
Commitments and contingencies (Note 15)00
Shareholders’ equity:
Preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued— — 
Common stock, $0.01 par value, 25,000,000 shares authorized; 12,000,000 shares issued and 10,971,963 outstanding at September 30, 2021 and 12,000,000 shares issued and outstanding at December 31, 2020120 120 
Treasury stock (Note 6)(19,882)— 
Capital in excess of par value197,479 197,242 
Retained deficit(28,213)(18,140)
Total shareholders’ equity attributable to Unit Corporation149,504 179,222 
Non-controlling interests in consolidated subsidiaries226,786 246,371 
Total shareholders' equity376,290 425,593 
Total liabilities(1) and shareholders’ equity
$616,800 $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 September 30, 2021 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $51.3 million and $232.7 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated cash and cash equivalents of $49.6 million includes $12.3 million held by its VIE. Unit Corporation's consolidated total liabilities as of September 30, 2021 include total current and long-term liabilities of the VIE of $36.9 million and $5.6 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2020 include total current and long-term assets of the VIE of $45.8 million and $247.8 million, respectively, which can only settle obligations of the VIE. 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 16 – Variable Interest Entity Arrangements.












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

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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
  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)

2021202020212020
 Three Months Ended September 30, 2021One Month Ended September 30, 2020Two Months Ended August 31, 2020Nine Months Ended September 30, 2021One Month Ended September 30, 2020Eight Months Ended August 31, 2020
SuccessorSuccessorPredecessorSuccessorSuccessorPredecessor
Revenues:(In thousands except per share amounts)
Oil and natural gas$52,880 $13,643 $27,961 $149,874 $13,643 $103,439 
Contract drilling19,158 4,414 7,685 52,893 4,414 73,519 
Gas gathering and processing91,210 14,789 29,928 215,435 14,789 99,999 
Total revenues163,248 32,846 65,574 418,202 32,846 276,957 
Expenses:
Operating costs:
Oil and natural gas21,210 6,674 15,488 55,846 6,674 117,691 
Contract drilling15,357 2,989 5,410 41,308 2,989 51,810 
Gas gathering and processing62,621 9,852 17,822 147,340 9,852 68,045 
Total operating costs99,188 19,515 38,720 244,494 19,515 237,546 
Depreciation, depletion, and amortization15,294 7,467 17,919 49,169 7,467 115,496 
Impairments (Note 3)— 13,237 16,572 — 13,237 867,814 
Loss on abandonment of assets (Note 3)— — 1,179 — — 18,733 
General and administrative5,126 1,582 5,399 18,046 1,582 42,766 
Gain on disposition of assets(4,031)(222)(1,356)(6,213)(222)(89)
Total operating expenses115,577 41,579 78,433 305,496 41,579 1,282,266 
Income (loss) from operations47,671 (8,733)(12,859)112,706 (8,733)(1,005,309)
Other income (expense):
Interest, net (excludes interest expense of $5.4 million on senior subordinated notes subject to compromise, for the two and eight months ended August 31, 2020)(702)(826)(1,959)(3,895)(826)(22,824)
Write-off of debt issuance costs— — — — — (2,426)
Gain (loss) on derivatives (Note 12)(39,742)3,939 (4,250)(104,973)3,939 (10,704)
Loss on change in fair value of warrants (Note 13)(9,054)— — (12,628)— — 
Reorganization items, net(971)(1,155)141,002 (3,959)(1,155)133,975 
Other, net(7)39 1,931 (762)39 2,034 
Total other income (expense)(50,476)1,997 136,724 (126,217)1,997 100,055 
Income (loss) before income taxes(2,805)(6,736)123,865 (13,511)(6,736)(905,254)
Income tax benefit:
Current— — — — — (917)
Deferred— — (4,750)— — (13,713)
Total income taxes— — (4,750)— — (14,630)
Net income (loss)(2,805)(6,736)128,615 (13,511)(6,736)(890,624)
Net income (loss) attributable to non-controlling interest(9,100)2,232 73,484 (4,875)2,232 40,388 
Net income (loss) attributable to Unit Corporation$6,295 $(8,968)$55,131 $(8,636)$(8,968)$(931,012)
Net income (loss) attributable to Unit Corporation per common share (Note 7):
Basic$0.56 $(0.75)$1.03 $(0.74)$(0.75)$(17.45)
Diluted$0.55 $(0.75)$1.03 $(0.74)$(0.75)$(17.45)
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)

Shareholders' Equity Attributable to Unit Corporation
Common
Stock		Treasury StockCapital 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)— — — (1,937)1,346 (591)
Activity in stock-based compensation plans— — 74 — 16 90 
Balances, March 31, 2021 (Successor)$120 $— $197,316 $(20,077)$247,733 $425,092 
Net income (loss)— — — (12,994)2,879 (10,115)
Activity in stock-based compensation plans— — 245 — 15 260 
Distributions to non-controlling interests— — — — (12,344)(12,344)
Repurchase of common stock— (9,048)— — — (9,048)
Balances, June 30, 2021 (Successor)$120 $(9,048)$197,561 $(33,071)$238,283 $393,845 
Net income (loss) (1)
— — — 6,295 (9,100)(2,805)
Balance correction (Note 2)— — — (1,437)1,437 — 
Activity in stock-based compensation plans— — (82)— — (82)
Distributions to non-controlling interests— — — — (3,834)(3,834)
Repurchase of common stock— (10,834)— — — (10,834)
Balances, September 30, 2021 (Successor)$120 $(19,882)$197,479 $(28,213)$226,786 $376,290 
 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)
_______________________

1.Includes a one-time adjustment to correct an error discovered in our second quarter 2021 allocation of earnings from consolidated subsidiaries, as described in Note 2 - Summary Of Significant Accounting Policies.



















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 FLOWSCHANGES IN SHAREHOLDERS’ EQUITY (UNAUDITED)
- CONTINUED
  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



Shareholders' Equity Attributable to Unit Corporation
Common
Stock		Treasury StockCapital 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 loss— — — (770,494)(33,180)(803,674)
Activity in stock-based compensation plans103 — 2,391 — 31 2,525 
Balances, March 31, 2020 (Predecessor)10,694 — 646,543 (571,359)168,608 254,486 
Net income (loss)— — — (215,649)84 (215,565)
Activity in stock-based compensation plans10 — 1,585 — 16 1,611 
Balances, June 30, 2020 (Predecessor)10,704 — 648,128 (787,008)168,708 40,532 
Net income— — — 55,131 73,484 128,615 
Activity in stock-based compensation plans— — 2,025 — 8 2,033 
Balances, August 31, 2020 (Predecessor)10,704 — 650,153 (731,877)242,200 171,180 
Cancellation of predecessor equity(10,704)— (650,153)731,877 — 71,020 
Issuance of successor common stock120 — 197,203 — — 197,323 
Balances, September 1, 2020 (Successor)120 — 197,203 — 242,200 439,523 
Net income (loss)— — — (8,968)2,232 (6,736)
Activity in stock-based compensation plans— — 9 — 4 13 
Balances, September 30, 2020 (Successor)$120 $— $197,212 $(8,968)$244,436 $432,800 
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)
 SuccessorSuccessorPredecessor
 Nine Months Ended September 30, 2021One Month Ended September 30, 2020Eight Months Ended August 31, 2020
OPERATING ACTIVITIES:(In thousands)
Net loss$(13,511)$(6,736)$(890,624)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization49,169 7,467 115,496 
Impairments (Note 3)— 13,237 867,814 
Loss on abandonment of assets (Note 3)— — 18,733 
Amortization of debt issuance costs and debt discount— — 1,079 
Loss on derivatives (Note 12)104,973 (3,939)10,704 
Cash payments on derivatives settled (Note 12)(22,647)(1,418)(4,244)
Loss on change in fair value of warrants (Note 13)12,628 — — 
Gain on disposition of assets(6,213)(222)(89)
Write-off of debt issuance costs— — 2,426 
Deferred tax expense— — (13,713)
Stock-based compensation plans268 13 4,786 
Credit loss expense1,695 — 3,155 
ARO liability accretion (Note 10)1,381 116 1,545 
Contract assets and liabilities, net (Note 4)2,462 324 2,459 
Capitalized contract fulfillment costs, net(353)— — 
Noncash reorganization items(67)1,024 (138,797)
Other, net(1,950)(2,623)12,164 
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable(16,255)(2,202)28,880 
Material and supplies— — 89 
Prepaid expenses and other1,063 194 (3,849)
Accounts payable12,350 2,366 (18,381)
Accrued liabilities(1,607)2,082 44,811 
Income taxes1,128 — 906 
Contract advances(88)(9)(394)
Net cash provided by (used in) operating activities124,426 9,674 44,956 
INVESTING ACTIVITIES:
Capital expenditures(21,117)(1,598)(25,775)
Producing properties and other acquisitions— — (382)
Proceeds from disposition of property and equipment71,350 576 6,018 
Net cash provided by (used in) investing activities50,233 (1,022)(20,139)
FINANCING ACTIVITIES:
Borrowings under line of credit, including borrowings under DIP credit facility30,700 — 87,400 
Payments under line of credit(126,600)(4,000)(64,100)
DIP financing costs— — (990)
Exit facility financing costs— — (3,225)
Net payments on finance leases(3,216)(350)(2,757)
Employee taxes paid by withholding shares— — (43)
Distributions to non-controlling interests(16,178)— — 
Repurchase of common stock(19,882)— — 
Bank overdrafts(2,631)— (8,733)
Net cash provided by (used in) financing activities(137,807)(4,350)7,552 
Net increase (decrease) in cash, restricted cash and cash equivalents36,852 4,302 32,369 
Cash, restricted cash, and cash equivalents, beginning of period12,714 32,940 571 
Cash, restricted cash, and cash equivalents, end of period$49,566 $37,242 $32,940 
The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - CONTINUED

 SuccessorSuccessorPredecessor
 Nine Months Ended September 30, 2021One Month Ended September 30, 2020Eight Months Ended August 31, 2020
 (In thousands)
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Interest paid$4,307 $251 $6,417 
Income taxes(1,128)— — 
Reorganization items4,026 131 4,822 
Changes in accounts payable and accrued liabilities related to purchases of property and equipment(3,356)(128)8,561 
Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations(1,674)(215)29,189 
Non-cash trade of property and equipment— — 1,403 





































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


NOTE 1 – BASIS OF 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 Pipeline Company, L.L.C. (Superior) of which we own 50%.

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

Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company (UPC), we develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are mainly 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. The company evaluates subsequent events through the resultsdate the financial statements are issued.
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In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 852, Reorganizations, the company adopted fresh start accounting upon emergence from the Chapter 11 Cases resulting in the company becoming a new entity for financial reporting purposes. We evaluated the events between September 1, 2020 and September 3, 2020 and concluded that the use of an accounting convenience date of September 1, 2020 (Fresh Start Reporting Date) would not have a material impact to be realized for the full year of 2017, or that we realized for the full year of 2016.

Certain amounts in the unaudited condensed consolidated financial statements. This was reflected in our unaudited condensed consolidated balance sheet as of September 1, 2020. Accordingly, our unaudited condensed consolidated financial statements and notes after September 1, 2020, are not comparable to the unaudited condensed consolidated financial statements and notes before that date. To facilitate the financial statement presentations, we refer to the reorganized company in these unaudited condensed consolidated financial statements and notes as the "Successor" for periods subsequent to August 31, 2020, and "Predecessor" for periods prior to September 1, 2020. Furthermore, the unaudited condensed consolidated financial statements and notes have been presented with a "black line" division to delineate the lack of comparability between the Predecessor and Successor.

We consolidate the activities of Superior, a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, (SP Investor) which qualifies as a Variable Interest Entity (VIE) under GAAP. We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power to direct those activities that most significantly affect the economic performance of Superior as further described in Note 16 – Variable Interest Entity Arrangements.

During third quarter 2021, management identified an error in the allocation of earnings from Superior between Unit Corporation and non-controlling interests related to the three months ended June 30, 2021 as well as an unrelated error in the initial allocation of equity between Unit Corporation and non-controlling interests as of the Fresh Start Reporting Date. The impact of the errors were not material to any of our prior period financial statements and both errors were corrected with one-time adjustments in the three months ended September 30, 2021. As a result, during the three months ended September 30, 2021, net income (loss) attributable to Unit Corporation was increased by $12.2 million with a corresponding decrease to net income (loss) attributable to non-controlling interest, and retained earnings (deficit) was reduced by $1.4 million with a corresponding decrease to non-controlling interest in consolidated subsidiaries.

During second quarter 2021, management identified errors in our inter-segment eliminations presentation between oil and natural gas revenues and gas gathering and processing revenues as well as between gas gathering and processing operating costs and general and administrative expenses. The impacts of the errors were not material to any of our prior period financial statements and the current year impacts on the three months ended March 31, 2021 were corrected with a one-time adjustment in the three months ended June 30, 2021. As a result, during the three months ended June 30, 2021, oil and natural gas revenues were decreased by $8.6 million with a corresponding increase to gas gathering and processing revenues while general and administrative expenses were increased by $0.9 million with a corresponding decrease to gas gathering and processing operating costs.

Also during second quarter 2021, management identified separate errors in our prior period accrual of oil and natural gas revenues as well as oil and natural gas operating costs. The impacts of the errors were not material to any of our prior period financial statements and the errors were corrected with a one-time adjustment in the three months ended June 30, 2021. As a result, during the three months ended June 30, 2021, oil and natural gas revenues were increased by $3.9 million and oil and natural gas operating costs were decreased by $3.4 million.

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

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Recent Accounting Pronouncements

Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging— Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The FASB issued ASU 2020-06 which simplifies the accounting for convertible instruments by removing certain accounting models which separate the embedded conversion features from the host contract for convertible instruments. The ASU further removes certain settlement conditions that are required for equity contracts to qualify for the derivative scope exception and simplifies the diluted earnings per share calculation in certain areas. The ASU is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. Early adoption is permitted. We are currently evaluating the potential impact on our financial statements.

Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 which provides optional expedients and exceptions for applying GAAP 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 unaudited condensed 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 unaudited condensed 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 three and nine months ended September 30, 2021.

During the one month ended September 30, 2020, the application of the full cost accounting rules require usresulted in a pre-tax non-cash ceiling impairment of $13.2 million primarily due to reviewthe use of average 12-month historical commodity prices for the ceiling test compared to forward prices for the fresh start fair value estimates.

During the three months ended March 31, 2020, due to the increased uncertainty in our business, we determined our undeveloped acreage would not be fully developed and thus the carrying values of certain of our unproved oil and gas properties were not recoverable resulting in an impairment of $226.5 million. That impairment had a corresponding increase to our depletion base and contributed to our recorded full cost ceiling impairment during the three months ended March 31, 2020. We recorded a non-cash full cost ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax) in the three months ended March 31, 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. There were no additional triggering events identified during the eight months ended August 31, 2020.

In addition to the impairment evaluations of our proved and unproved oil and gas properties in the three months ended March 31, 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast, we determined that some were no longer expected to be used and wrote off the assets for total expense of $17.6 million during the three months ended March 31, 2020. These amounts are reported in loss on abandonment of assets in our unaudited condensed consolidated statements of operations. There were no additional triggering events identified during the eight months ended August 31, 2020.


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Contract Drilling

There were no impairments recorded during the three and nine months ended September 30, 2021.

During the two months ended August 31, 2020, we recorded expense of $1.1 million related to the write-down of certain equipment that we consider abandoned. These amounts are reported in loss on abandonment of assets in our unaudited condensed consolidated statements of operations.

At March 31, 2020, due to market conditions, we performed impairment testing on two asset groups which were comprised of our SCR diesel-electric drilling rigs and our BOSS drilling rigs. We concluded that the net book value of the SCR drilling rigs asset group was not recoverable through estimated undiscounted cash flows and recorded a non-cash impairment charge of $407.1 million in the three months ended March 31, 2020. We also recorded additional non-cash impairment charges of $3.0 million for other miscellaneous drilling equipment. These charges are included within impairments in our unaudited condensed consolidated statements of operations.

We used the income approach to determine the fair value of the SCR drilling rigs asset group. This approach uses significant assumptions including management’s best estimates of the expected future cash flows and the estimated useful life of the asset group. Fair value determination requires a considerable amount of judgement and is sensitive to changes in underlying assumptions and economic factors. As a result, there is no assurance the fair value estimates made for the impairment analysis will be accurate in the future. There were no additional triggering events identified during the eight months ended August 31, 2020 or one month ended September 30, 2020.

We concluded that no impairment was needed on the BOSS drilling rigs asset group as of March 31, 2020 as the undiscounted cash flows exceeded the $242.5 million carrying value of the asset group by a relatively minor margin. Some of the more sensitive assumptions used in evaluating the contract drilling rigs asset groups for potential impairment included forecasted utilization, gross margins, salvage values, discount rates, and terminal values. There were no additional triggering events identified during the eight months ended August 31, 2020 or one month ended September 30, 2020.

Mid-Stream

There were no impairments recorded during the three and nine months ended September 30, 2021. We will continue to monitor for potential impairment in the fourth quarter of 2021 as certain systems negotiate renewed terms with their current volume commitments nearing an end.

During the three months ended March 31, 2020, we determined that the carrying value of certain long-lived asset groups in southern Kansas, and central Oklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. We recorded non-cash impairment charges of $64.0 million based on the estimated fair value of the asset groups. These charges are included within impairments in our unaudited condensed consolidated statement of operations. There were no additional triggering events identified during the eight months ended August 31, 2020 or one month ended September 30, 2020.

NOTE 4 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Our revenue streams are reported under 3 segments: oil and natural gas, contract drilling, and mid-stream which is consistent with how we report our segment revenue (as reflected in Note 18 – 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.


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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 September 30, 2021, we had 9 contract drilling contracts with remaining terms ranging from two to fifteen months.

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 unaudited condensed consolidated balance sheetsSeptember 30,
2021		December 31,
2020		Change
(In thousands)
Assets
Current contract assetsPrepaid expenses and other$1,700 $6,084 $(4,384)
Non-current contract assetsOther assets— 173 (173)
Total contract assets$1,700 $6,257 $(4,557)
Liabilities
Current contract liabilitiesCurrent portion of other long-term liabilities$1,919 $2,583 $(664)
Non-current contract liabilitiesOther long-term liabilities158 1,589 (1,431)
Total contract liabilities2,077 4,172 (2,095)
Contract assets (liabilities), net$(377)$2,085 $(2,462)
Included below is the adjustment to demand fees from adopting ASC 805, Business Combinations, which requires that606, Revenue from contracts with customers over the acquired assets and liabilities be recorded at their fair valuesremaining term of the contracts as of September 30, 2021.

ContractRemaining Term of Contract202120222023 and beyondTotal Remaining Impact to Revenue
(In thousands)
Demand fee contracts1 - 13 months$(997)$1,374 $— $377 

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NOTE 5 – DIVESTITURES

Oil and Natural Gas

The company initiated an asset divestiture program at the acquisition date.beginning of 2021 to sell certain non-core oil and gas properties and reserves (the “Divestiture Program”). On October 4, 2021, the company announced that it is expanding the Divestiture Program to now include the potential sale of additional properties, including up to all of UPC’s oil and gas properties and reserves. The following table summarizescompany expects to enhance various severance and certain other related benefits in response to the adjustedDivestiture Program.

On June 25, 2021, the company entered into a purchase priceand sale agreement in which we agreed to sell substantially all of our wells and the estimated values of assets acquired 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 areleases related thereto located near Oklahoma City, Oklahoma for $19.5 million, subject to change as additional information becomes availablecustomary closing and is assessed by us (in thousands):post-closing adjustments. The divestiture closed on August 16, 2021, with an effective date of May 1, 2021. The sale of these assets did not result in a significant alteration of the full cost pool, and therefore no gain or loss was recognized.

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
On March 30, 2021, the company entered into a purchase and sale agreement in 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 did not result in a significant alteration of the full cost pool, and therefore no gain or loss was recognized.
(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 $5.0 million of other non-core oil and natural gas assets, net of related expenses, for $18.0during the nine months ended September 30, 2021, compared to $1.2 million during the first nineeight months of 2017, compared to $43.6 millionended August 31, 2020 and none during the first nine months of 2016. Proceeds from those salesone month ended September 30, 2020. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.


Contract Drilling

We sold non-core contract drilling assets for proceeds of $4.3 million and $8.2 million, net of related expenses, during the three and nine months ended September 30, 2021, compared to $2.0 million and $4.8 million during the two and eight months ended August 31, 2020, and $0.6 million during the one month ended September 30, 2020. These proceeds resulted in net gains of $3.1 million and $5.2 million during the three and nine months ended September 30, 2021, compared to $1.3 million and $1.4 million during the two and eight months ended August 31, 2020, and $0.2 million during the one month ended September 30, 2020.

Corporate and Other

On September 17, 2021, we closed the sale of our corporate headquarters building and land for $35.0 million, subject to customary closing and post-close adjustments resulting in a gain of $0.9 million net of $2.2 million of transaction costs. In conjunction with the closing, we entered into a multi-year lease for a portion of the building.

NOTE 46 – CAPITAL STOCK

On June 16, 2021, the company repurchased an aggregate of 600,000 shares of its common stock from the Lenders (as defined in Note 9 - Long-Term Debt and Other Long-Term Liabilities) which received these shares as an exit fee during the company’s reorganization. The Lenders were paid $15.00 per share for their respective shares, for an aggregate cash purchase price of $9.0 million. The cash purchase price and direct acquisition costs are reflected as treasury stock on the unaudited condensed consolidated balance sheets as of September 30, 2021.

In June 2021, the company's board of directors (the Board) authorized repurchasing up to $25.0 million of the company’s outstanding common stock. In October 2021, the Board authorized an increase from $25.0 million of authorized repurchases to $50.0 million. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. The company has no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice.

As of September 30, 2021, the company has repurchased a total of 350,037 shares at an average share price of $26.70 for an aggregate purchase price of $9.3 million under the repurchase program.

During the three months ended September 30, 2021, the company also repurchased 78,000 shares at a share price of $19.07 which were not part of the repurchase program.

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Subsequent to September 30, 2021, the company repurchased an additional 711,926 shares under the repurchase program at an average share price of $34.80 for an aggregate purchase price of $24.8 million bringing the aggregate shares repurchased under all methods since the Effective Date to 1,739,963 shares.

NOTE 7 – EARNINGS (LOSS) PER SHARE


Information related to the calculation of earnings (loss) per share follows:
  
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)


Dueattributable to the net lossUnit Corporation for the three months ended September 30, 2016, approximately 546,000 weighted average shares2021, one month ended September 30, 2020, and two months ended August 31, 2020 is as follows:

Earnings (Loss)
(Numerator)		Weighted
Shares
(Denominator)		Per-Share
Amount
 (In thousands except per share amounts)
For the three months ended September 30, 2021 (Successor)
Basic earnings attributable to Unit Corporation per common share$6,295 11,311 $0.56 
Effect of dilutive restricted stock— 109 (0.01)
Diluted earnings attributable to Unit Corporation per common share$6,295 11,420 $0.55 
For the one month ended September 30, 2020 (Successor)
Basic loss attributable to Unit Corporation per common share$(8,968)12,000 $(0.75)
Effect of dilutive stock options and restricted stock— — — 
Diluted loss attributable to Unit Corporation per common share(8,968)12,000 $(0.75)
For the two months ended August 31, 2020 (Predecessor)
Basic earnings attributable to Unit Corporation per common share$55,131 53,519 $1.03 
Effect of dilutive stock options and restricted stock— — — 
Diluted earnings attributable to Unit Corporation per common share$55,131 53,519 $1.03 

Information related to stock options, restricted stock, and SARs were antidilutive and excluded from the calculation above.of earnings (loss) per share attributable to Unit Corporation for the nine months ended September 30, 2021 and eight months ended August 31, 2020 is as follows:


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:
Earnings (Loss) (Numerator)Weighted Shares (Denominator)Per-Share Amount
(In thousands except per share amounts)
For the nine months ended September 30, 2021 (Successor)
Basic loss attributable to Unit Corporation per common share$(8,636)11,735 $(0.74)
Effect of dilutive restricted stock— — — 
Diluted loss attributable to Unit Corporation per common share$(8,636)11,735 $(0.74)
For the eight months ended August 31, 2020 (Predecessor)
Basic loss attributable to Unit Corporation per common share$(931,012)53,368 $(17.45)
Effect of dilutive stock options and restricted stock— — — 
Diluted loss attributable to Unit Corporation per common share$(931,012)53,368 $(17.45)
  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, 2016,2021, approximately 424,00062,690 weighted average shares related to stock options,of restricted stock and SARs were antidilutive and were excluded from the earnings per share 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:
17
  Nine Months Ended
  September 30,
  2017 2016
Stock options and SARs 178,755
 240,270
Average exercise price $47.75
 $49.29

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NOTE 58 – ACCRUED LIABILITIES


Accrued liabilities consisted of:
September 30,
2021		December 31,
2020
 (In thousands)
Employee costs$7,692 $8,878 
Lease operating expenses3,792 6,405 
Capital expenditures6,998 3,461 
Taxes6,576 2,324 
Interest payable402 884 
Legal settlement— 2,070 
Other1,519 1,182 
Total accrued liabilities$26,979 $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 69 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES


Long-Term Debt


OurAs of the date indicated, our long-term debt consisted of the following:
September 30,
2021		December 31,
2020
(In thousands)
Current portion of long-term debt:
Exit credit agreement with an average interest rate of 6.6% at December 31, 2020$— $600 
Long-term debt:
Exit credit agreement with an average interest rate of 6.6% at December 31, 2020$— $98,400 
Superior credit agreement with an average interest rate of 2.1% at September 30, 2021$3,100 $— 

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

Credit Agreement. Our Senior Credit Agreement (credit agreement) is scheduledOn July 27, 2021, the company finalized the second amendment to mature on April 10, 2020.the Exit credit agreement. Under the second amendment, the company obtained confirmation that the Term Loan had been paid in full prior to the amendment date and received one-time waivers related to the disposition of assets.

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On October 19, 2021, the company finalized the third amendment to the Exit credit agreement. Under the third amendment, the company requested, and was granted, a reduction in the RBL borrowing base from $140.0 million to $80.0 million in addition to less restrictive terms as it relates to capital expenditures, required hedges, and the use of proceeds from the disposition of certain assets, while also amending certain financial covenants.

The Exit credit agreement requires the amount we can borrow iscompany to comply with certain financial ratios, including a covenant that the lessercompany will not permit the Net Leverage Ratio (as defined in the Exit credit agreement) as of the amount we elect as the commitment amount or the valuelast day of the borrowingfiscal quarters ended (i) December 31, 2020 and March 31, 2021, to be greater than 4.00 to 1.00, (ii) June 30, 2021 and September 30, 2021, to be greater than 3.75 to 1.00, and (iii) December 31, 2021 and any fiscal quarter thereafter, to be greater than 3.25 to 1.00. In addition, beginning with the fiscal quarter ended December 31, 2020, the company may not (a) permit the Current Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 1.00 to 1.00 or (b) permit the Interest Coverage Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 2.50 to 1.00. The Exit credit agreement also contains provisions, among others, that limit certain capital expenditures, and require certain hedging activities. The Exit credit agreement further requires the company to provide quarterly financial statements within 45 days after the end of each of the first three quarters of each fiscal year and annual financial statements within 90 days after the end of each fiscal year. As of September 30, 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 the company’s ownership interests in Superior.

At September 30, 2021, we had no long-term borrowings and $3.2 million of letters of credit outstanding under the Exit credit agreement.

Superior Credit Agreement. On May 10, 2018, Superior signed a five-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions (Superior credit agreement). The maturity date of borrowings under the Superior credit agreement is March 10, 2023. The amounts borrowed under the Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base as determinedrate (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 lenders, butLIBOR or Administrative Agent determines in either event notgood 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 exceed $875.0 million. Our borrowing base and elected commitmentthe Administrative Agent in the London Interbank Market, the Administrative Agent may select a replacement index.

Superior 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. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the 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 were2021, 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 September 30, 2021, we had $3.1 million of borrowings and $1.4 million of letters of credit outstanding under the 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:
September 30,
2021		December 31,
2020
 (In thousands)
Asset retirement obligation (ARO) liability$26,372 $23,356 
Workers’ compensation11,311 10,164 
Finance lease obligations— 3,216 
Contract liability2,077 4,172 
Separation benefit plans2,675 4,201 
Gas balancing liability4,238 3,997 
Other long-term liability1,323 1,321 
47,996 50,427 
Less: current portion6,522 11,168 
Total other long-term liabilities$41,474 $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 710 – 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:indicated (in thousands):

  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)ARO liability, December 31, 2020 (Successor):We$23,356 
Accretion of discount1,381 
Liability incurred4 
Liability settled(852)
Liability sold our interest in a number(1,925)
Revision of non-core wells to unaffiliated third-parties during the first nine months of 2017 and 2016, respectively.estimates (1)
4,408 
ARO liability, September 30, 2021 (Successor):26,372 
Less: current portion2,455 
Total long-term ARO$23,917 
_______________________ 
1.Plugging liability estimates were revised in 2021 for updates in the cost of services used to plug wells over the preceding year as well as estimated inflation and discount rates. We had various upward and downward adjustments.

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(2)Plugging
ARO liability, December 31, 2019 (Predecessor)$66,627 
Accretion of discount1,545 
Liability incurred465 
Liability settled(838)
Liability sold(487)
Revision of estimates were revised in both 2017 and 2016(1)
(28,328)
ARO liability, August 31, 2020 (Predecessor)38,984 
Fresh start adjustments(14,393)
ARO liability, August 31, 2020 (Successor)24,591 
Accretion of discount116 
Liability incurred141 
Liability settled(51)
Liability sold— 
Revision of estimates125 
ARO liability, September 30, 2020 (Successor)24,922 
Less current portion2,186 
Total long-term ARO$22,736 
_______________________ 
1.Plugging liability estimates were revised in 2020 for updates in the cost of services used to plug wells over the preceding year. 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-BASED11 – STOCK-BASED COMPENSATION


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

On April 27, 2021, 109,008 aggregate restricted stock units (RSUs) were granted to the members of the Board pursuant to the LTIP with a weighted-average grant date fair value of $12.90 per unit. The RSUs will 25% vest on each of the following dates: the date that is thirteen months following the date of grant, September 3, 2022, September 3, 2023, and September 3, 2024. The fair value of these grants is measured based on the closing stock price on grant date and compensation expense recognized in general and administrative on the unaudited condensed consolidated statements of operations over the vesting period. There were no other grants made during the nine months ended September 30, 2021.

No stock options we had:
  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 ator restricted stock units were granted during the two or eight months ended August 31, 2020, or during the one month ended September 30, 2017 is approximately $14.2 million, of which $1.7 million is anticipated to be capitalized.2020.

Also on the Effective Date, the company's equity-based awards outstanding immediately before the Effective Date were cancelled. 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 sharescancellation of the company's commonawards resulted in an acceleration of unrecorded stock is authorized for issuancecompensation expense during the Predecessor Period. Under the Plan, the company issued Warrants to eligible participantsholders of those equity-based awards that were outstanding immediately before the Effective Date who did not opt out of releases under the amended plan with 2,000,000 shares being the maximum numberPlan.
21
Table of shares that can be issued as "incentiveContents

There were no outstanding restricted stock options."

We did not grant any SARsawards or stock options during either of the three or nineone month periods ending ended September 30, 2017 or 2016. We did not grant any restricted stock awards during either of2020. For the three monthother periods, 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:we had:
SuccessorPredecessorSuccessorPredecessor
Three Months Ended September 30, 2021Two Months Ended August 31, 2020Nine Months Ended September 30, 2021Eight Months Ended August 31, 2020
(In millions)
Recognized stock compensation expense$(0.1)$2.0 $0.1 $6.1 
Tax benefit on stock-based compensation— $0.5 — $1.5 


  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 1012 – 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 9 – Long-Term Debt and Other Long-Term Liabilities. As of September 30, 2017,2021, 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 unaudited condensed consolidated balance sheets 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 Statementsunaudited condensed consolidated statements of Operations.operations.


AtAs of September 30, 2017, the following2021, these derivatives were outstanding:
TermCommodityContracted Volume
Weighted Average��
Average 
Fixed Price
Contracted Market
Oct'17Oct'21 - Dec'21Natural gas –- basis swap70,00030,000 MMBtu/day$3.038(0.22)NGPL TEXOK
Oct'21Natural gas - swap50,000 MMBtu/day$2.82IF –- NYMEX (HH)
Nov’17 – Dec'17Nov'21 - Dec'21Natural gas –- swap60,00045,000 MMBtu/day$2.9602.90IF –- NYMEX (HH)
Jan’18 – Dec'18Jan'22 - Dec'22Natural gas –- swap20,0005,000 MMBtu/day$3.0132.61IF –- NYMEX (HH)
Nov’17 – Dec'17Jan'23 - Dec'23Natural gas – basis- swap20,00022,000 MMBtu/day$(0.215)2.46IF –- 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'17Oct'21 - Dec'21Natural gas – three-way collarCrude oil - swap25,000 MMBtu/3,373 Bbl/day$2.9045.14WTI - $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
22
_______________________
(1)    Type
Table of liquid involved is propane.Contents

The following tables present the fair values and locations of the derivative transactions recorded inon our Unaudited Condensed Consolidated Balance Sheets:unaudited condensed consolidated balance sheets:
  Derivative Liabilities
  Fair Value
 Classification on the unaudited condensed consolidated balance sheetsSeptember 30,
2021		December 31,
2020
  (In thousands)
Commodity derivatives:
CurrentCurrent derivative liability$59,962 $1,047 
Long-termNon-current derivative liability28,069 4,659 
Total derivative liabilities$88,031 $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.unaudited condensed consolidated balance sheets.


Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statementsunaudited condensed consolidated statements of Operationsoperations for the three months ended September 30:periods indicated:
SuccessorSuccessorPredecessorSuccessorPredecessor
Three Months Ended September 30, 2021One Month Ended September 30, 2020Two Months Ended August 31, 2020Nine Months Ended September 30, 2021Eight Months Ended August 31, 2020
 (In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $(12,940), $(1,418), $(3,552), $(22,647), and $(4,244), respectively$(39,742)$3,939 $(4,250)$(104,973)$(10,704)
$(39,742)$3,939 $(4,250)$(104,973)$(10,704)
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 1113 – FAIR VALUE MEASUREMENTS


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


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 levelLevel 1 either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.


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


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


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The following tables set forth our recurring fair value measurements:
September 30, 2021
 Level 2Level 3Effect
of Netting		Net Amounts Presented
 (In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets$— $— $— $— 
Liabilities(88,031)— — (88,031)
Total commodity derivatives$(88,031)$— $— $(88,031)

 September 30, 2017December 31, 2020
 Level 1 Level 2 Level 3 
Effect
of Netting
 Net Amounts Presented Level 2Level 3Effect
of Netting		Net Amounts Presented
 (In thousands) (In thousands)
Financial assets (liabilities):          Financial assets (liabilities):
Commodity derivatives:          Commodity derivatives:
Assets $—
 $662
 $1,964
 $(1,562) $1,064
Assets$3,436 $— $(3,436)$— 
Liabilities —
 (2,002) (478) 1,562
 (918)Liabilities(9,142)— 3,436 (5,706)
Total commodity derivatives —
 (1,340) 1,486
 —
 146
Total commodity derivatives$(5,706)$— $— $(5,706)
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 no collateral has been posted as of September 30, 2017.2021.



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 and collars using estimated internal discounted cash flow calculations based on the NYMEX futures index.


Level 3 Fair Value Measurements


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


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Table of Contents
There was no Level 3 commodity derivative activity during the three or nine months ended September 30, 2021, or during the one month ended September 30, 2020. The following table is a reconciliation of our levelLevel 3 commodity derivative fair value measurements:measurements for the two and eight months ended August 31, 2020:
  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.


The following table provides quantitative information about our Level 3 unobservable inputs
Predecessor
Two Months Ended August 31, 2020Eight Months Ended August 31, 2020
 (In thousands)
Beginning of period$843 $1,204 
Total gains or losses (realized and unrealized):
Included in earnings (1)
(405)872 
Settlements(438)(2,076)
End of period$— $— 
Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period$(843)$(1,204)
_______________________
1.Commodity derivative activity is reported in the unaudited condensed consolidated statements of operations in gain (loss) on derivatives.

Our valuation at September 30, 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.

Our valuation at September 30, 20172021 and December 31, 2020 reflected that the risk of non-performance by our counterparties was immaterial.


Warrants. Warrants are recorded at their fair value utilizing the Black-Scholes-Merton option model. The inputs to the model require judgment, including estimating the strike price, expected term, and the associated volatility. The Warrants had fair values of $13.5 million and $0.9 million as of September 30, 2021 and December 31, 2020, respectively, with the increases of $4.8 million and $8.3 million for the three and nine months ended September 30, 2021, respectively, reflected as Loss on change in fair value of warrants in the unaudited condensed consolidated statements of operations. The Warrants will continue to be adjusted to fair value at each reporting period until the Warrants meet the definition of an equity instrument, at which time they will be reported as shareholders' equity and no longer subject to future fair value adjustments.

Fair Value of Other Financial Instruments


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


At September 30, 2017,2021, the carrying values on the Unaudited Condensed Consolidated Balance Sheetsunaudited 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 710 – Asset Retirement Obligations.


NOTE 14 – 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 operating lease agreements do not include options to purchase the leased property.

During the three months ended September 30, 2021, we entered into an operating lease agreement for our headquarters office space which generated right of use assets and liabilities at lease inception of $8.4 million.
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The following table sets forth the maturity of our operating lease liabilities as of September 30, 2021:
Amount
(In thousands)
Ending September 30,
2022$5,017 
20233,339 
20242,968 
20252,095 
20262,002 
2027 and beyond54 
Total future payments15,475 
Less: Interest1,689 
Present value of future minimum operating lease payments13,786 
Less: Current portion4,399 
Total long-term operating lease payments$9,387 

Finance Leasesunder ASC 842

In 2014, Superior entered into finance lease agreements for 20 compressors with initial terms of seven years and an option to purchase the assets at 10% of their then fair market value at the end of the term. These finance leases were discounted using annual rates of 4.00% and the underlying assets were included in gas gathering and processing equipment. In May 2021, Superior purchased the leased assets for $3.0 million.
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The following table shows information about our lease assets and liabilities on our unaudited condensed consolidated balance sheets:
Classification on the unaudited condensed consolidated balance sheetsSeptember 30,
2021		December 31,
2020
(In thousands)
Assets
Operating right of use assetsRight of use assets$13,800 $5,592 
Finance right of use assetsProperty, plant, and equipment, net— 7,281 
Total right of use assets$13,800 $12,873 
Liabilities
Current liabilities:
Operating lease liabilitiesCurrent operating lease liabilities$4,399 $4,075 
Finance lease liabilitiesCurrent portion of other long-term liabilities— 3,216 
Non-current liabilities:
Operating lease liabilitiesOperating lease liabilities9,387 1,445 
Finance lease liabilitiesOther long-term liabilities— — 
Total lease liabilities$13,786 $8,736 

The following table shows certain information related to the lease costs for our finance and operating leases for the periods indicated:
SuccessorSuccessorPredecessorSuccessorPredecessor
Three Months Ended September 30, 2021One Month Ended September 30, 2020Two Months Ended August 31, 2020Nine Months Ended September 30, 2021Eight Months Ended August 31, 2020
(In thousands)
Components of total lease cost:
Amortization of finance leased assets$— $350 $696 $1,248 $2,757 
Interest on finance lease liabilities— 15 35 33 165 
Operating lease cost1,043 328 965 3,053 3,604 
Short-term lease cost (1)
3,120 867 1,448 7,893 8,190 
Variable lease cost— 29 58 — 223 
Total lease cost$4,163 $1,589 $3,202 $12,227 $14,939 
_______________________
1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $0.8 million, $— million, $0.1 million, $1.0 million, and $1.5 million for the three months ended September 30, 2021, the one month ended September 30, 2020, the two months ended August 31, 2020, the nine months ended September 30, 2021, and eight months ended August 31, 2020, respectively.

The following table shows supplemental cash flow information related to leases for the periods indicated:
SuccessorSuccessorPredecessor
Nine Months Ended September 30, 2021One Month Ended September 30, 2020Eight Months Ended August 31, 2020
(In thousands)
Cash paid for amounts in the measurement of lease liabilities:
Operating cash flows for operating leases$3,125 $351 $3,849 
Financing cash flows for finance leases$3,216 $350 $2,757 

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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 leases3.95.51%
_______________________
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 1215 – 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 equipmenttransport our natural gas from various systems for approximately $1.1 million over the next twelve months and production inventory.Future minimum rental payments under the terms of the leases are approximately $3.2 million, $0.8 million, $0.4 million, $0.3 million, and less than $0.1 million in twelve month periods beginning October 1, 2017 (and through the end of 2021), respectively. Total rent expense incurred was $6.4 million and $8.7 million for the first ninesix months thereafter.

During the second quarter of 2017 and 2016, respectively.

In 2014, our mid-stream segment2018, as part of the Superior transaction (see description in Note 16 – Variable Interest Entity Arrangements), we entered into capital lease agreements for 20 compressors with initial termsa contractual obligation committing us to spend $150.0 million (Drilling Commitment Amount) to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. If we do not spend all of seven years. Estimated annual capital lease payments under the terms duringDrilling Commitment Amount, SP Investor receives 100% of cash distributions until the four successive twelve month periods beginning October 1, 2017 (and throughDrilling Commitment Adjustment Amount (as defined in the endAmended and Restated Limited Liability Company Agreement (Agreement)) is satisfied. The total amount spent towards the $150.0 million as 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 2021.2021 was $24.8 million. At September 30, 2021, if we elected not to drill or spend any additional money in the enddesignated area before December 31, 2021, the maximum amount of the term, our mid-stream segment hasDrilling Commitment Adjustment Amount would be $72.6 million. We do not anticipate meeting the option to purchasecontractual obligation over the assets at 10% of their then fair market value.remaining commitment period.


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. In any one year, these repurchases are limited to 20% of the units outstanding. We had no repurchases in the first nine months of 2016. We made repurchases of $2,900 during the first nine months of 2017.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 also automatically stayed all proceedings and actions against the Predecessor company (other than certain regulatory enforcement matters). Effective at emergence from the Chapter 11 Cases, the automatic stay was terminated and replaced with the injunction provisions in the Confirmation Order and the Plan.

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

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

On March 11, 2016, a putative class action lawsuit was filed against UPC styled Cockerell Oil Properties, Ltd., v. Unit Petroleum 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.

Settlement

In August 2020, UPC reached an agreement to settle these class actions. Under the settlement, UPC agreed to recognize class proof of claims in the amount of $15.75 million for Cockerell Oil Properties, Ltd. vs. Unit Petroleum Company, and $29.25 million in Chieftain Royalty Company vs. Unit Petroleum Company. Under the Plan, these settlements will be treated as allowed general unsecured claims against UPC. This settlement has been approved by the United States Bankruptcy Court for the Southern District of Texas, Houston Division in Case No. 20-32740 under the caption In re Unit Corporation, et al. and, in accordance with the Plan, the settlement amounts have committed to purchase approximately $3.9 millionbeen satisfied by distribution of new drilling rig components.the plaintiffs’ proportionate share of New Common Stock.



NOTE 1316 – 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, 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 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, such as operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $0.3 million. Superior's creditors have no recourse to our general credit. Unit is not a party to and does not guarantee Superior's credit agreement. The obligations under Superior's credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.

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The Agreement specifies how future distributions are to be allocated among the Members. Future distributions may be from Available Cash or made in conjunction with a 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 not receiving cash distributions proportionate to its ownership percentage. Circumstances that could result in Unit receiving less than a proportionate share of 1933,future distributions include, but may not be limited to, Unit not fulfilling the drilling commitment before December 31, 2021 as amended, including salesdescribed in Note 15 – Commitments and Contingencies or a cumulative return to SP Investor of less than the 7% Liquidation IRR Hurdle provided for SP Investor in the Agreement. Generally, the 7% Liquidation IRR Hurdle calculation requires cumulative distributions to SP Investor in excess of its original $300.0 million investment sufficient to provide SP Investor a 7% IRR on its capital contributions to Superior before any liquidation distribution is made directly onto Unit. At September 30, 2021, liquidation distributions first paid to SP Investor of $362.6 million would be required for SP Investor to reach its 7% Liquidation IRR Hurdle at which point Unit would then be entitled to receive up to $362.6 million of the NYSE, onremaining liquidation distributions to satisfy Unit's 7% Liquidation IRR Hurdle with any other existing trading marketremaining liquidation distributions paid as outlined within the Agreement. After the fifth anniversary of the effective date of the sale, either owner may force a sale of Superior to a third-party or a liquidation of Superior's assets.

Effective at emergence from the Chapter 11 Cases, we allocate Unit's and SP Investor's share of earnings and losses from Superior in our unaudited condensed consolidated statement of operations using the hypothetical liquidation at book value (HLBV) method of accounting which is a balance-sheet approach that calculates the change in the hypothetical amount Unit and SP Investor would be entitled to receive if Superior were liquidated at book value at the end of each period, adjusted for any contributions made and distributions received during the Sharesperiod. 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 September 30, 2021.

As the primary beneficiary of this VIE, we consolidate in our financial statements the financial position, results of operations, and conditionscash flows of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal tradingthis VIE. All intercompany balances and sales practices and applicable state and federal law, rules and regulationstransactions between us and the rulesVIE are eliminated in our unaudited condensed consolidated financial statements. Cash distributions of income, net of agreed on expenses, and estimated expenses are allocated to the NYSE, to sellequity owners as specified in 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).relevant agreements.

We are not obligated to make any salesOn November 1, 2021, Superior acquired gas gathering and processing assets including a cryogenic processing plant and approximately 1,620 miles 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 Shareslow-pressure gathering pipeline along with related compressor stations and meters located in southern Kansas for $13.0 million, subject to the Agreement or (2) the terminationcustomary closing and post-closing adjustments.

Superior paid cash distributions totaling $24.7 million in April 2021 related to cumulative available cash as 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 agreedMarch 31, 2021, $7.7 million in July 2021 related 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 foravailable cash generated during 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
 $—

ChangesJune 30, 2021, and $13.9 million in accumulated other comprehensive income by component, net of tax, forOctober 2021 related to available cash generated during the three months ended September 30, are as follows:2021. Unit and SP Investor each received 50% of these distributions. See Note 15 – Commitments and Contingencies for discussion of the Granite Wash/Buffalo Wallow drilling commitment and the potential impact on future distributions.

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  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
 $—
The amounts below reflect the eliminations of intercompany transactions and balances consistent with the presentation in the unaudited condensed consolidated balance sheets.
September 30,
2021		December 31,
2020
 (In thousands)
Current assets:
Cash and cash equivalents$12,286 $11,642 
Accounts receivable36,487 27,427 
Prepaid expenses and other2,540 6,746 
Total current assets51,313 45,815 
Property and equipment:
Gas gathering and processing equipment259,642 251,403 
Transportation equipment2,086 1,748 
261,728 253,151 
Less accumulated depreciation, depletion, amortization, and impairment34,878 10,466 
Net property and equipment226,850 242,685 
Right of use asset3,926 2,823 
Other assets1,961 2,309 
Total assets$284,050 $293,632 
Current liabilities:
Accounts payable$26,921 $17,045 
Accrued liabilities6,441 3,777 
Current operating lease liability1,570 1,762 
Current portion of other long-term liabilities1,919 5,799 
Total current liabilities36,851 28,383 
Long-term debt3,100 — 
Operating lease liability2,356 1,013 
Other long-term liabilities158 1,589 
Total liabilities$42,465 $30,985 



Components of accumulated other comprehensive income were as follows forNOTE 17 – INCOME TAXES

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 thethree and nine months ended September 30, 2021, the company’s effective income tax rate was 0.0% compared to (3.8)% and 1.6% for the two and eight months ended August 31, 2020, and 0.0% for the one month ended September 30, 2020. The decrease was due to the continued need of a full valuation allowance against our net deferred tax asset coming out of bankruptcy and as a result of fresh start accounting. These rates differ from the statutory rate of 21.0% mostly due to changes in our valuation allowance, our non-controlling interests in consolidated subsidiaries, and state income taxes.

Deferred Tax Asset Valuation Allowance

The company has concluded that it is more likely than not that the net deferred tax asset will not be realized and has recorded a full valuation allowance, reducing the net deferred tax asset as of September 30, 2021, to zero. The company will continue to evaluate whether the valuation allowance is needed in future reporting periods and it will remain until the company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, significant improvements in commodity prices, significant increase in rig utilization, a material and sizable asset acquisition or disposition, and taxable events that could result from one or more future potential transactions. The valuation allowance does not prohibit the company from utilizing the tax attributes if the company recognizes taxable income. As long as follows:the company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the company will not have significant deferred income tax expense or benefit.
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  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
 $—


Net Operating Loss

As of September 30, 2021, and after consideration of the tax attribute reductions of IRC Section 108 and finalization of the company’s 2020 federal income tax return, the company has an expected federal net operating loss carryforward of $420.3 million of which $225.3 million is subject to expiration between 2021 and 2037.

NOTE 1418 – INDUSTRY SEGMENT INFORMATION


We have three3 main business segments offering different products and services within the energy industry:
 
•Oil and natural gas,
•Contract drilling, and
Mid-stream•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 September 30, 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$66,202 $— $— $— $(13,322)$52,880 
Contract drilling —
 25,819
 —
 —
 —
 25,819
Contract drilling— 19,158 — — — 19,158 
Gas gathering and processing —
 —
 63,090
 —
 (14,355) 48,735
Gas gathering and processing— — 92,022 — (812)91,210 
Total revenues 78,854
 25,819
 63,090
 —
 (14,355) 153,408
Total revenues66,202 19,158 92,022 — (14,134)163,248 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 27,710
 —
 —
 —
 (1,696) 26,014
Oil and natural gas22,022 — — — (812)21,210 
Contract drilling —
 19,137
 —
 —
 —
 19,137
Contract drilling— 15,357 — — — 15,357 
Gas gathering and processing —
 —
 48,397
 —
 (12,659) 35,738
Gas gathering and processing— — 76,823 — (14,202)62,621 
Total operating costs 27,710
 19,137
 48,397
 —
 (14,355) 80,889
Total operating costs22,022 15,357 76,823 — (15,014)99,188 
Depreciation, depletion, and amortization 27,135
 11,318
 11,436
 80
 —
 49,969
Depreciation, depletion, and amortization5,311 1,576 8,143 264 — 15,294 
Impairments 49,443
 —
 —
 —
 —
 49,443
Total expenses 104,288
 30,455
 59,833
 80
 (14,355) 180,301
Total expenses27,333 16,933 84,966 264 (15,014)114,482 
Total operating income (loss)(1)
 (25,434) (4,636) 3,257
 (80) —
  
General and administrative expense —
 —
 —
 (8,852) —
 (8,852)
General and administrativeGeneral and administrative— — — 4,246 880 5,126 
Gain on disposition of assets —
 151
 —
 3
 —
 154
Gain on disposition of assets(14)(3,091)— (926)— (4,031)
Gain on derivatives —
 —
 —
 6,969
 —
 6,969
Interest expense, net —
 —
 —
 (10,002) —
 (10,002)
Income (loss) from operationsIncome (loss) from operations38,883 5,316 7,056 (3,584)— 47,671 
Loss on derivativesLoss on derivatives— — — (39,742)— (39,742)
Loss on change in fair value of warrantsLoss on change in fair value of warrants— — — (9,054)— (9,054)
Reorganization items, netReorganization items, net— — — (971)— (971)
Interest, netInterest, net— — (250)(452)— (702)
Other —
 —
 —
 3
 —
 3
Other51 (34)(24)— — (7)
Income (loss) before income taxes $(25,434) $(4,485) $3,257
 $(11,959) $—
 $(38,621)Income (loss) before income taxes$38,934 $5,282 $6,782 $(53,803)$— $(2,805)
_______________________
(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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Successor
 Nine Months Ended September 30, 2017One Month Ended September 30, 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$13,644 $— $— $— $(1)$13,643 
Contract drilling —
 137,617
 —
 —
 (9,558) 128,059
Contract drilling— 4,414 — — — 4,414 
Gas gathering and processing —
 —
 198,632
 —
 (48,139) 150,493
Gas gathering and processing— — 17,284 — (2,495)14,789 
Total revenues 256,241
 137,617
 198,632
 —
 (57,697) 534,793
Total revenues13,644 4,414 17,284 — (2,496)32,846 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 99,349
 —
 —
 —
 (3,476) 95,873
Oil and natural gas6,892 — — — (218)6,674 
Contract drilling —
 99,794
 —
 —
 (8,581) 91,213
Contract drilling— 2,989 — — — 2,989 
Gas gathering and processing —
 —
 156,525
 —
 (44,663) 111,862
Gas gathering and processing— — 12,130 — (2,278)9,852 
Total operating costs 99,349
 99,794
 156,525
 —
 (56,720) 298,948
Total operating costs6,892 2,989 12,130 — (2,496)19,515 
Depreciation, depletion, and amortization 71,544
 41,896
 32,547
 5,558
 —
 151,545
Depreciation, depletion, and amortization4,199 526 2,658 84 — 7,467 
ImpairmentsImpairments13,237 — — — — 13,237 
Total expenses 170,893
 141,690
 189,072
 5,558
 (56,720) 450,493
Total expenses24,328 3,515 14,788 84 (2,496)40,219 
Total operating income (loss)(1)
 85,348
 (4,073) 9,560
 (5,558) (977)  
General and administrative expense —
 —
 —
 (26,902) —
 (26,902)
General and administrativeGeneral and administrative— — — 1,582 — 1,582 
Gain on disposition of assets 176
 106
 58
 813
 —
 1,153
Gain on disposition of assets(10)(212)— — — (222)
Income (loss) from operationsIncome (loss) from operations(10,674)1,111 2,496 (1,666)— (8,733)
Gain on derivatives —
 —
 —
 21,019
 —
 21,019
Gain on derivatives— — — 3,939 — 3,939 
Interest expense, net —
 —
 —
 (28,807) —
 (28,807)
Reorganization items, netReorganization items, net— — — (1,155)— (1,155)
Interest, netInterest, net— — (137)(689)— (826)
Other —
 —
 —
 14
 —
 14
Other29 1 8 1 — 39 
Income (loss) before income taxes $85,524
 $(3,967) $9,618
 $(39,421) $(977) $50,777
Income (loss) before income taxes$(10,645)$1,112 $2,367 $430 $— $(6,736)
_______________________
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.


1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.
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Predecessor
 Nine Months Ended September 30, 2016Two Months Ended August 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 $206,318
 $—
 $—
 $—
 $—
 $206,318
Oil and natural gas$27,962 $— $— $— $(1)$27,961 
Contract drilling —
 88,786
 —
 —
 —
 88,786
Contract drilling— 7,685 — — — 7,685 
Gas gathering and processing —
 —
 168,668
 —
 (35,875) 132,793
Gas gathering and processing— — 34,132 — (4,204)29,928 
Total revenues 206,318
 88,786
 168,668
 —
 (35,875) 427,897
Total revenues27,962 7,685 34,132 — (4,205)65,574 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 98,070
 —
 —
 —
 (5,379) 92,691
Oil and natural gas15,895 — — — (407)15,488 
Contract drilling —
 66,489
 —
 —
 —
 66,489
Contract drilling— 5,410 — — — 5,410 
Gas gathering and processing —
 —
 129,681
 —
 (30,496) 99,185
Gas gathering and processing— — 21,620 — (3,798)17,822 
Total operating costs 98,070
 66,489
 129,681
 —
 (35,875) 258,365
Total operating costs15,895 5,410 21,620 — (4,205)38,720 
Depreciation, depletion, and amortization 89,378
 34,431
 34,410
 218
 —
 158,437
Depreciation, depletion, and amortization9,975 853 6,750 341 — 17,919 
Impairments 161,563
 —
 —
 —
 —
 161,563
Impairments16,572 — — — — 16,572 
Total expenses 349,011
 100,920
 164,091
 218
 (35,875) 578,365
Total expenses42,442 6,263 28,370 341 (4,205)73,211 
Total operating income (loss)(1)
 (142,693) (12,134) 4,577
 (218) —
  
General and administrative expense —
 —
 —
 (25,811) —
 (25,811)
Gain (loss) on disposition of assets (324) 1,467
 (302)—
(18) —
 823
Loss on abandonment of assetsLoss on abandonment of assets87 1,092 — — — 1,179 
General and administrativeGeneral and administrative— — — 5,399 — 5,399 
Gain on disposition of assetsGain on disposition of assets(102)(1,251)(3)0— — (1,356)
Income (loss) from operationsIncome (loss) from operations(14,465)1,581 5,765 (5,740)— (12,859)
Loss on derivatives —
 —
 —
 (4,774) —
 (4,774)Loss on derivatives— — — (4,250)— (4,250)
Interest expense, net —
 —
 —
 (30,225) —
 (30,225)
Reorganization items, netReorganization items, net15,504 (183,664)(71,016)380,178 — 141,002 
Interest, netInterest, net— — (828)(1,131)— (1,959)
Other —
 —
 —
 (11) —
 (11)Other428 1,426 11 66 — 1,931 
Income (loss) before income taxes $(143,017) $(10,667) $4,275
 $(61,057) $—
 $(210,466)Income (loss) before income taxes$1,467 $(180,657)$(66,068)$369,123 $— $123,865 
_______________________
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes.
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.
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Successor
Nine Months Ended September 30, 2021
Oil and Natural GasContract DrillingMid-StreamCorporate and OtherEliminationsTotal Consolidated
(In thousands)
Revenues: (1)
Oil and natural gas$181,003 $— $— $— $(31,129)$149,874 
Contract drilling— 52,893 — — — 52,893 
Gas gathering and processing— — 217,954 — (2,519)215,435 
Total revenues181,003 52,893 217,954 — (33,648)418,202 
Expenses:
Operating costs:
Oil and natural gas58,365 — — — (2,519)55,846 
Contract drilling— 41,308 — — — 41,308 
Gas gathering and processing— — 181,109 — (33,769)147,340 
Total operating costs58,365 41,308 181,109 — (36,288)244,494 
Depreciation, depletion, and amortization19,442 4,721 24,238 768 — 49,169 
Impairment— — — — — — 
Total expenses77,807 46,029 205,347 768 (36,288)293,663 
General and administrative— — — 15,406 2,640 18,046 
(Gain) loss on disposition of assets(101)(5,237)75 (950)— (6,213)
Income (loss) from operations103,297 12,101 12,532 (15,224)— 112,706 
Loss on derivatives— — — (104,973)— (104,973)
Loss on change in fair value of warrants— — — (12,628)— (12,628)
Reorganization items, net— — — (3,959)— (3,959)
Interest, net— — (666)(3,229)— (3,895)
Other140 (17)(863)(22)— (762)
Income (loss) before income taxes$103,437 $12,084 $11,003 $(140,035)$— $(13,511)
_______________________
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

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Predecessor
Eight Months Ended August 31, 2020
 Oil and Natural GasContract DrillingMid-StreamCorporate and OtherEliminationsTotal Consolidated
 (In thousands)
Revenues: (1)
Oil and natural gas$103,443 $— $— $— $(4)$103,439 
Contract drilling— 73,519 — — — 73,519 
Gas gathering and processing— — 114,531 — (14,532)99,999 
Total revenues103,443 73,519 114,531 — (14,536)276,957 
Expenses:
Operating costs:
Oil and natural gas119,664 — — — (1,973)117,691 
Contract drilling— 51,811 — — (1)51,810 
Gas gathering and processing— — 80,607 — (12,562)68,045 
Total operating costs119,664 51,811 80,607 — (14,536)237,546 
Depreciation, depletion, and amortization68,762 15,544 29,371 1,819 — 115,496 
Impairments393,726 410,126 63,962 — — 867,814 
Total expenses582,152 477,481 173,940 1,819 (14,536)1,220,856 
Loss on abandonment of assets17,641 1,092 — — — 18,733 
General and administrative— — — 42,766 — 42,766 
(Gain) loss on disposition of assets(160)(1,390)(18)1,479 — (89)
Loss from operations(496,190)(403,664)(59,391)(46,064)— (1,005,309)
Loss on derivatives— — — (10,704)— (10,704)
Write-off of debt issuance costs— — — (2,426)— (2,426)
Reorganization items, net15,504 (183,664)(71,016)373,151 — 133,975 
Interest, net— — (1,888)(20,936)— (22,824)
Other458 1,449 50 77 — 2,034 
Income (loss) before income taxes$(480,228)$(585,879)$(132,245)$293,098 $— $(905,254)
_______________________
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

NOTE 19 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

For the following footnote:

•we were called "Parent",
•the direct subsidiaries were 100% owned by the Parent and the guarantee was full and unconditional and joint and several and called "Combined Guarantor Subsidiaries", and
•Superior and its subsidiaries and the Operator were called "Non-Guarantor Subsidiaries."

The following unaudited supplemental condensed consolidating financial information reflects the Parent's separate accounts, the combined accounts of the Combined Guarantor Subsidiaries', the combined accounts of the Non-Guarantor Subsidiaries', the combined consolidating adjustments and eliminations, and the Parent's consolidated amounts for the periods indicated.
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Condensed Consolidating Statements of Operations (Unaudited)
Predecessor
Two Months Ended August 31, 2020
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Revenues$— $35,647 $34,132 $(4,205)$65,574 
Expenses:
Operating costs— 21,307 21,619 (4,206)38,720 
Depreciation, depletion, and amortization341 10,828 6,750 — 17,919 
Impairments— 16,572 — — 16,572 
Loss on abandonment of assets— 1,179 — — 1,179 
General and administrative expense— 5,399 — — 5,399 
Gain on disposition of assets— (1,353)(3)— (1,356)
Total operating costs341 53,932 28,366 (4,206)78,433 
Income (loss) from operations(341)(18,285)5,766 1 (12,859)
Interest, net(1,131)— (828)— (1,959)
Write-off of debt issuance costs— — — — — 
Loss on derivatives(4,250)— — — (4,250)
Reorganization items380,178 (168,160)(71,016)— 141,002 
Other, net68 1,853 10 — 1,931 
Income (loss) before income taxes374,524 (184,592)(66,068)1 123,865 
Income tax benefit(4,750)— — — (4,750)
Equity in net earnings from investment in subsidiaries, net of taxes(250,659)— — 250,659 — 
Net income (loss)128,615 (184,592)(66,068)250,660 128,615 
Less: net income attributable to non-controlling interest73,484 — 73,484 (73,484)73,484 
Net income (loss) attributable to Unit Corporation$55,131 $(184,592)$(139,552)$324,144 $55,131 

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Predecessor
Eight Months Ended August 31, 2020
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Revenues$— $176,962 $114,531 $(14,536)$276,957 
Expenses:
Operating costs— 171,476 80,607 (14,537)237,546 
Depreciation, depletion, and amortization1,819 84,306 29,371 — 115,496 
Impairments— 803,852 63,962 — 867,814 
Loss on abandonment of assets— 18,733 — — 18,733 
General and administrative— 42,766 — — 42,766 
(Gain) loss on disposition of assets1,479 (1,550)(18)— (89)
Total operating costs3,298 1,119,583 173,922 (14,537)1,282,266 
Income (loss) from operations(3,298)(942,621)(59,391)1 (1,005,309)
Interest, net(20,936)— (1,888)— (22,824)
Write-off of debt issuance costs(2,426)— — — (2,426)
Loss on derivatives(10,704)— — — (10,704)
Reorganization items373,151 (168,160)(71,016)— 133,975 
Other, net79 1,906 49 — 2,034 
Income (loss) before income taxes335,866 (1,108,875)(132,246)1 (905,254)
Income tax benefit(14,630)— — — (14,630)
Equity in net earnings from investment in subsidiaries, net of taxes(1,241,120)— — 1,241,120 — 
Net loss(890,624)(1,108,875)(132,246)1,241,121 (890,624)
Less: net income attributable to non-controlling interest40,388 — 40,388 (40,388)40,388 
Net loss attributable to Unit Corporation$(931,012)$(1,108,875)$(172,634)$1,281,509 $(931,012)
                            



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Condensed Consolidating Statements of Cash Flows (Unaudited)
Predecessor
Eight Months Ended August 31, 2020
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities$(207,593)$82,769 $32,922 $136,858 $44,956 
INVESTING ACTIVITIES:— 
Capital expenditures(986)(14,585)(10,204)— (25,775)
Producing properties and other acquisitions— (382)— — (382)
Proceeds from disposition of assets1,169 4,772 77 — 6,018 
Net cash provided by (used in) investing activities183 (10,195)(10,127)— (20,139)
FINANCING ACTIVITIES:
Borrowings under credit agreement, including borrowings under DIP credit facility55,300 — 32,100 — 87,400 
Payments under credit agreement(31,500)— (32,600)— (64,100)
DIP financing costs(990)— — — (990)
Exit facility financing costs(3,225)— — — (3,225)
Intercompany borrowings (advances), net210,398 (72,642)(898)(136,858)— 
Payments on finance leases— — (2,757)— (2,757)
Employee taxes paid by withholding shares(43)— — — (43)
Bank overdrafts(7,269)— (1,464)— (8,733)
Net cash provided by (used in) financing activities222,671 (72,642)(5,619)(136,858)7,552 
Net increase (decrease) in cash and cash equivalents15,261 (68)17,176 — 32,369 
Cash and cash equivalents, beginning of period503 68 — — 571 
Cash and cash equivalents, end of period$15,764 $— $17,176 $— $32,940 


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


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 our oil and natural gas segment.
segment, we are optimizing production and converting non-producing reserves to producing, with selective drilling activities in core areas. At the beginning of 2021, the company initiated an asset divestiture program in UPC to sell certain non-core oil and gas properties and reserves. On October 4, 2021, the company announced the expansion of its divestiture efforts to now include the potential sale of additional properties, including up to all of UPC’s oil and gas properties and reserves. Management continues to identify and execute on low cost capital projects to enhance production and reserves in this favorable price environment.


In our contract drilling segment, management reduced the number of drilling rigs available for use from 58 at December 31, 2020 to 21 during the second quarter of 2021 in order to focus on utilization of our BOSS drilling rigs and certain SCR rigs that are either currently under contract or candidates for future upgrades. Of the 21 rigs available for use, 13 are currently working, 4 are actively being marketed, and the remaining 4 will be considered for upgrade and marketing as future conditions warrant. 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.

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

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During the last two years commodity prices worldwide duringhave been volatile, and the past several years brought aboutoutlook for future oil and gas prices remains uncertain and subject to many factors. The following chart reflects the significant and adverse changes to our industry and us. As a result we reduced or stopped,fluctuations in the historical prices 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 reducegas:

unt-20210930_g2.jpg
The following chart reflects the rates for 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 rigssignificant fluctuations in the fourth quarterprices for NGLs:

unt-20210930_g3.jpg
_________________________
1.NGLs prices reflect a weighted-average, based on production, of 2016Mont Belvieu and Conway prices.



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Stock Repurchase Program

In June 2021, the second quarter of 2017, respectively. Our drilling rig segment's rig utilization increased from 16 drilling rigs working as of June 30, 2016,Board authorized repurchasing up 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 consequences for us (although, as noted, we are starting to see some improvements). Below are some of those consequences:

We incurred non-cash ceiling test write-downs in the first nine months of 2016 of $161.6$25.0 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, 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 quartercompany’s outstanding common stock. In October 2021, the Board authorized an increase from $25.0 million of 2017), our forward looking expectation is that weauthorized repurchases to $50.0 million. The repurchases will not recognize an impairment inbe made through open market purchases, privately negotiated transactions, or other available means. The company has no obligation to repurchase any shares under the fourth quarter of 2017. But commodity prices (and other factors) remain volatilerepurchase program and they could negatively impact the 12-month average price resulting in the potential for an impairment in the future.may suspend or discontinue it at any time without prior notice.
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 improvement2021, the company has repurchased a total of 57% over350,037 shares at an average share price of $26.70 for an aggregate purchase price of $9.3 million under the endrepurchase program.

Subsequent to September 30, 2021, the company repurchased an additional 711,926 shares under the repurchase program at an average share price of $34.80 for an aggregate purchase price of $24.8 million bringing the aggregate shares repurchased under all methods since the Effective Date to 1,739,963 shares.

Allocation of New Common Stock

As contemplated by the Plan, the company distributed 683,038 and 161,328 additional shares of New Common Stock to holders of the year). Operators have been increasing drilling, butsubordinated notes claims on July 26, 2021 and October 20, 2021, respectively, as a result of 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 salepro rata distribution of shares of our common stock. The offering allows us to sell shares, from time to time, up to an aggregateNew Common Stock out 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 salethe equity reserves established under the program. Net proceedsPlan for certain disputed claims against the company and UPC. The shares of New Common Stock were distributed pursuant to Section 1145 of the Bankruptcy Code (which generally exempts from registration under the offeringfederal and state securities laws the issuance of securities in exchange for interests in or claims against a debtor under a plan of reorganization). Pursuant to the Plan, all shares of New Common Stock were distributed in book-entry form through the facilities of The Depository Trust Company (DTC).

Warrants

Each holder of the Old Common Stock outstanding before the Effective Date that did not opt out of the release under the Plan, is entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant will initially be exercisable for one share of New Common Stock, subject to adjustment as provided in the Warrant Agreement. The exercise price of the Warrants will be useddetermined, and the Warrants will become exercisable, once the Debtors have completed the claims reconciliation process and resolved any objections to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstandingdisputed claims under our revolving credit facility, and general corporate purposes.

On April 3, 2017, we closedthe Bankruptcy Petitions. The initial exercise price per share for the Warrants will be set at an acquisitionamount that implies a recovery by holders 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 valuethe Subordinated Notes of consideration given was $54.3 million. The effectivethe $650 million principal amount of the Subordinated Notes plus interest thereon to the May 15, 2021 maturity 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 barrelsthe Notes. The Warrants expire on the earliest of oil equivalent (Boe), an increase(i) September 3, 2027, (ii) consummation 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 drilledCash Sale (as defined in the first nine monthsWarrant Agreement) or (iii) the consummation 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 enda liquidation, dissolutions or winding up of the quarter,company (such earliest date, the third-party processing plant forExpiration Date). Each Warrant that is not exercised on or before the majorityExpiration Date will expire, and all rights under that Warrant and the Warrant Agreement will cease on the Expiration Date.

The warrants issued to holders 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,company’s Old Common Stock that did not opt-out of the Texas Panhandle ice storm inreleases under the first quarter,Plan 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 quarterthat owned their shares 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:
old common stock through Direct Registration are outlined below:
TermIssuance DateCommodityContracted Volume
Weighted Average 
Fixed Price
Contracted MarketWarrants Issued
Oct'17December 21, 2020Natural 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:
1,770,552 
TermFebruary 11, 202142,511 CommodityContracted Volume
Weighted Average 
Fixed Price
Contracted Market
Apr'18 – Oct'18July 29, 202110,521 Natural gas – swap10,000 MMBtu/day$2.990IF – NYMEX (HH)
Apr'18 – Sep'18October 13, 20215,005 
Liquids – swap (1)
Total1,828,589 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 operated incompany expects to issue approximately 14,729 more Warrants to 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 pricing for oil and natural gas that began during the second half of 2016 has increased demand for drilling rigs. Our drilling rig count bottomed out at 13 drilling rigs operating during the second quarter of 2016, but increased to 21 drilling rigs operating at the end of 2016. Our drilling rig count continued to increase during the first three quarters of 2017 to 36 drilling rigs during the third quarter but we ended the third quarter with 33 operating drilling rigs. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates.

We have 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 termholders 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.

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 doOld Common Stock that did 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 certainopt-out of the contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts–releases under which we receive a sharethe Plan and owned their shares through Direct Registration.

43
Table of the proceeds from the sale of the NGLs–our revenues from those commodity-based contracts fluctuate based on the price of NGLs.Contents

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, endeavorrequirements for at least the next 12 months.

Below is a summary of certain financial information for the periods indicated:
 SuccessorSuccessorPredecessor
Percent
Change (1)
 Nine Months Ended September 30, 2021One Month Ended September 30, 2020Eight Months Ended August 31, 2020
 (In thousands except percentages)
Net cash provided by (used in) operating activities$124,426 $9,674 $44,956 128 %
Net cash provided by (used in) investing activities50,233 (1,022)(20,139)NM
Net cash provided by (used in) financing activities(137,807)(4,350)7,552 NM
Net increase (decrease) in cash, restricted cash and cash equivalents$36,852 $4,302 $32,369 
_________________________
1.NM - A percentage calculation is not meaningful due to anticipate potential covenant compliance issues, and work, where possible, with our lenders to address those issues ahead of time.a zero-value denominator or a percentage change greater than 200.


  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 (used in) operating activities in the first nine months of 2017 decreased2021 increased by $13.0$69.8 million as compared to the first nine 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.


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 the majority of future capital budgets to be focused on low cost capital projects to enhance production and reserves in this favorable price environment.


Cash flows used inNet cash provided by (used in) investing activities increased by $96.7 million for the first nine months of 2017 compared to the first nine months of 2016. The change was due primarily to an increase in capital expenditures due to an oil and gas property acquisition, the restarting of our drilling program 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 flows provided by financing activities increased by $109.5$71.4 million for the first nine months of 20172021 compared to the first nine months of 2016.2020. The increasechange was primarily due to proceeds received from the ATM common stock programdisposition of our corporate headquarters building and land, an increase in book overdraftsproceeds received from the disposition of other non-core assets, and a decrease in 2017 coupled with almost no changecapital expenditures resulting from a decrease in the number of wells drilled and oil and gas property acquisitions.




44
Table of Contents
Cash Flows from Financing Activities

Net cash provided by (used in) financing activities decreased by $141.0 million for the first nine months of 2021 compared to the first nine months of 2020. The decrease was primarily due to higher payments on our credit agreements, lower net borrowing after paying down long-term debt in 2016.borrowings under our credit agreements, distributions made to non-controlling interests, the repurchase of common stock, and lower bank overdrafts.


At September 30, 2017,2021, we had unrestricted cash and cash equivalents totaling $0.8$49.6 million, and had borrowed $162.1which includes $12.3 million of cash and cash equivalents held by Superior, and $3.1 million of outstanding borrowings, all of which was borrowed under the $475.0 million we had elected to then have available under ourSuperior credit agreement. OurUnit had no outstanding borrowings under the Exit 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, 2017 and 2016 and for the nine months ended September 30, 2017 and 2016:30:
SuccessorSuccessor
 20212020
 (In thousands)
Working capital$(30,367)$21,624 
Current portion of long-term debt$— $400 
Long-term debt$3,100 $143,600 
Shareholders’ equity attributable to Unit Corporation$149,504 $188,364 

  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 negative working capital of $62.2$30.4 million and $42.3positive working capital of $21.6 million as of September 30, 20172021 and 2016,2020, respectively. The increasedecrease in negative working capital is primarily due to increasedhigher current derivative liabilities, warrant liability, and accounts payable, due to increased activity in our drilling program and increased drilling rig utilization and the reclassification of current deferred tax asset to long-term asset per ASU 2015-17 partially offset by increasedincreases in cash and cash equivalents and accounts receivable from increased revenues and the change in the value of outstanding derivatives. Our credit agreement is 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.receivable. The effect of our derivative contracts increaseddecreased working capital by $0.4$60.0 million as of September 30, 20172021 and decreasedincreased working capital by $5.6$1.3 million as of September 30, 2016.2020.


The following table summarizes certain operating information:Our Credit Agreements

  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)%

OilExit Credit Agreement. On the Effective Date, under the terms of the Plan, the company entered into an amended and Natural Gas Operations

Any significant change in oil, NGLs, or natural gas prices hasrestated credit agreement (the Exit credit agreement), providing for a material effect on our revenues, cash flow,$140.0 million senior secured revolving credit facility (RBL Facility) and a $40.0 million senior secured term loan facility, among (i) the value of our oil, NGLs,company, UDC, 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 onUPC (together, 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, withoutBorrowers), (ii) 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,guarantors party thereto, including the effectcompany and all 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 constantits subsidiaries existing 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)Effective Date (other than Superior Pipeline Company, L.L.C. and its subsidiaries), our forward looking expectation is that we will not recognize an impairment in(iii) 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 price of $100.0 million. We intend to useborrowings under this Exit credit agreement is March 1, 2024.

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 September 30, 2021, we have athad $3.1 million outstanding long-term borrowings under the endExit credit agreement. During the nine month period ended September 30, 2021, the company repaid $126.6 million of each quarter:borrowings under the Exit credit agreement with cash generated from operations as well as from proceeds from divestitures of non-core assets.


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

On July 27, 2021, the company finalized the second amendment to the Exit credit agreement. Under the second amendment, the company obtained confirmation that the Term Loan had been paid in full prior to the amendment date and received one-time waivers related to the disposition of assets.

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On October 19, 2021, the company finalized the third amendment to the Exit credit agreement. Under the third amendment, the company requested, and was granted, a current ratio (as definedreduction in the RBL borrowing base from $140.0 million to $80.0 million in addition to less restrictive terms as it relates to capital expenditures, required hedges, and the use of proceeds from the disposition of certain assets, while also amending certain financial covenants.

Superior Credit Agreement. On May 10, 2018, Superior signed a five-year, $200.0 million senior secured revolving credit agreement) of not less than 1facility with an option to 1.

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

a senior indebtedness ratio of senior indebtednessamount up to consolidated EBITDA (as defined in the$250.0 million, subject to certain conditions (Superior credit agreement) for. The maturity date of borrowings under 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, theSuperior 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.

is March 10, 2023. As of September 30, 2017,2021, we were in compliance withhad $3.1 million of borrowings and $1.4 million of letters of credit outstanding under the Superior credit agreement covenants.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 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 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.


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 10 gross wells (15.10(0.77 net wells) in the first nine months of 2017 compared to 15 gross wells (7.77 net wells)drilled by other operators in the first nine months of 2016.2021 compared to 27 gross wells (6.16 net wells) drilled by other operators in which we participated in the first nine months of 2020.

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 nine months of 20172021 by this segment, excluding $56.4a $1.6 million for acquisitions and a $2.8 millionincrease in the ARO liability, totaled $143.7$7.1 million. Capital expenditures for the first nine months of 2016,2020, excluding $0.4 million for acquisitions and a $29.4$28.2 million reduction in the ARO liability, totaled $91.9$10.3 million.


On June 25, 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 near Oklahoma City, Oklahoma for $19.5 million, subject to customary closing and post-closing adjustments. The divestiture closed on August 16, 2021, with an effective date of May 1, 2021. The sale of these assets did not result in a significant alteration of the full cost pool, and therefore no gain or loss was recognized.

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 did not result in a significant alteration of the full cost pool and therefore, no gain or loss was 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 $5.0 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 forother non-core oil NGLs, and natural gas demand for oil, NGLs,assets, net of related expenses, during the nine months ended September 30, 2021, compared to $1.2 million during the eight months ended August 31, 2020 and natural gas,none during the one month ended September 30, 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 disposal or sale of our non-core, idle drilling rig fleet. We incurred $0.9 million in capital expenditures during the first quarternine months of 2017, we were awarded a term contract2021, compared to build our tenth BOSS rig. Construction was completed and the 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. We have spent $30.0$4.0 million for capital expenditures during the first nine months of 2017,2020.

We sold non-core contract drilling assets for proceeds of $8.2 million, net of related expenses, during the nine months ended September 30, 2021, compared to $7.2proceeds of $4.8 million for capital expenditures during the firsteight months ended August 31, 2020 and none during the one month ended September 30, 2020. These proceeds resulted in net gains of $5.2 million during the nine months of 2016.ended September 30, 2021, compared to $1.4 million during the eight months ended August 31, 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 nine months of 2017,2021, our mid-stream segment incurred $10.1$8.6 million in capital expenditures as compared to $11.1$10.2 million in the first nine months of 2016.2020. For 2017, our estimated2021, we estimate total capital expenditures areof approximately $18.9 million.$24.2 million, primarily for the gas gathering and processing assets acquired in November 2021 as well as the maintenance and operation of our assets, and connection of new wells.



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, 2017,2021, based on our third quarter 20172021 average daily production, the approximated percentages of our production under derivative contracts are as follows:
202120222023
Daily oil production87%64%36%
Daily natural gas production63%54%30%

  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, 20172021 evaluation, we believe the risk of non-performance by our counterparties is not material. At September 30, 2017,2021, the fair values of the net assets (liabilities)liabilities we had with each of the counterparties to our commodity derivative transactions are as follows:
September 30, 2021
(In thousands)
Bank of Oklahoma$(87,826)
Bank of Montreal(205)
Total net liabilities$(88,031)
  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 net 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 billedinstruments 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 conditionsstatements 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:


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
SuccessorSuccessorPredecessorSuccessorPredecessor
Three Months Ended September 30, 2021One Month Ended September 30, 2020Two Months Ended August 31, 2020Nine Months Ended September 30, 2021Eight Months Ended August 31, 2020
 (In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $(12,940), $(1,418), $(3,552), $(22,647), and $(4,244), respectively$(39,742)$3,939 $(4,250)$(104,973)$(10,704)
$(39,742)$3,939 $(4,250)$(104,973)$(10,704)
47
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
Quarter Ended September 30, 20172021 versus Quarter Ended September 30, 20162020
Provided below is a comparison of selected operating and financial data:
 SuccessorSuccessorPredecessor
Percent
Change (1)
 Quarter Ended September 30, 2021One Month Ended September 30, 2020Two Months Ended August 31, 2020
(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations$177,382 $35,342 $69,779 69 %
Total revenue, after inter-segment eliminations$163,248 $32,846 $65,574 66 %
Net income (loss)$(2,805)$(6,736)$128,615 (102)%
Net income (loss) attributable to non-controlling interest$(9,100)$2,232 $73,484 (112)%
Net income (loss) attributable to Unit Corporation$6,295 $(8,968)$55,131 (86)%
Oil and Natural Gas:
Revenue, before inter-segment eliminations$66,202 $13,644 $27,962 59 %
Operating costs, before inter-segment eliminations$22,022 $6,892 $15,895 (3)%
Average oil price (Bbl)$47.66 $28.11 $28.64 67 %
Average oil price excluding derivatives (Bbl)$70.53 $36.94 $38.55 86 %
Average NGLs price (Bbl)$27.42 $7.47 $8.53 NM
Average NGLs price excluding derivatives (Bbl)$27.42 $7.47 $8.53 NM
Average natural gas price (Mcf)$2.88 $1.72 $1.07 125 %
Average natural gas price excluding derivatives (Mcf)$3.69 $1.70 $1.10 186 %
Oil production (MBbls)329 167 341 (35)%
NGL production (MBbls)649 273 572 (23)%
Natural gas production (MMcf)6,805 2,849 6,184 (25)%
Contract Drilling:
Revenue, before inter-segment eliminations$19,158 $4,414 $7,685 58 %
Operating costs, before inter-segment eliminations$15,357 $2,989 5,410 83 %
Average number of drilling rigs in use11.0 6.0 4.6 116 %
Total drilling rigs available for use at the end of the period21 58 58 (64)%
Average dayrate on daywork contracts$17,502 $17,361 $16,596 4 %
Mid-Stream:
Revenue, before inter-segment eliminations$92,022 $17,284 $34,132 79 %
Operating costs, before inter-segment eliminations$76,823 $12,130 $21,620 128 %
Gas gathered--Mcf/day318,304 345,460 363,465 (11)%
Gas processed--Mcf/day128,161 145,263 149,483 (13)%
Gas liquids sold--gallons/day456,971 473,371 699,647 (27)%
Number of natural gas gathering systems17 18 18 (6)%
Number of processing plants11 11 11 — %
Corporate and Other:
General and administrative expense, before inter-segment eliminations$4,246 $1,582 $5,399 (39)%
Other income (expense):
Interest expense, net$(702)$(826)$(1,959)(75)%
Reorganization items, net$(971)$(1,155)$141,002 101 %
Gain (loss) on derivatives$(39,742)$3,939 $(4,250)NM
Loss on change in fair value of warrants$(9,054)$— $— — %
Income tax benefit$— $— $(4,750)100 %
Average interest rate6.5 %5.9 %2.7 %76 %
Average long-term debt outstanding$18,393 $146,267 $160,039 (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 %
48
_________________________
(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$24.6 million or 8%59% in the third quarter of 20172021 as compared to the third quarter of 2016 primarily due to higher commodity prices partially offset from reduced 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.

Oil and natural gas operating costs increased $7.9 million or 30% between the comparative third quarters of 2017 and 2016 due to higher LOE and production taxes partially offset by lower saltwater disposal expenses.

Depreciation, depletion, and amortization (“DD&A”) decreased $0.7 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 drilled in the first nine 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 2017 versus the third quarter of 2016. The increase was due primarily to a 116% increase in the average number of drilling rigs in use partially offset by a 6% decrease in the average dayrate. Average drilling rig utilization increased from 16.0 drilling rigs in the third quarter of 2016 to 34.6 drilling rigs in the third quarter of 2017.

Drilling operating costs increased $15.6 million or 82% between the comparative third quarters of 2017 and 2016. The increase was due primarily to more drilling rigs operating. Contract drilling depreciation increased $4.0 million or 35% also due primarily to more drilling rigs operating.

Mid-Stream

Our mid-stream revenues increased $2.7 million or 5% in the third quarter of 2017 as compared to the third quarter of 2016 due primarily to increases in NGLs and condensate prices. Gas processed volumes per day decreased 8% between the comparative quarters primarily due to declines in existing volumes, fewer new wells connected to our processing systems, and no offload volume at our Hemphill facility in 2017. Gas gathered volumes per day decreased 11% between the comparative quarters primarily due to declining gathered volumes on our Appalachian systems.

Operating costs increased $2.4 million or 7% in the third quarter of 2017 compared to the third quarter of 2016 primarily due to 26% higher gas purchase prices partially offset by a 9% decrease in 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 $0.4 million or 4% in the third quarter of 2017 compared to the third quarter of 2016 primarily due to an increase in employee costs.

Other Income (Expense)

Interest expense, net of capitalized interest, decreased $0.1 million between the comparative third quarters of 2017 and 2016 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. Our average interest rate increased from 5.7% in the third quarter of 2016 to 6.0% in the third quarter of 2017 and our average debt outstanding was $61.6 million lower in the third quarter of 2017 as compared to the third quarter 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 $9.6 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 $16.4 million between the comparative third quarters of 2017 and 2016 primarily due to increased pre-tax income. Our effective tax rate was 32.3% for the third quarter of 2017 compared to 37.8% for the third quarter of 2016. The rate change was primarily due to the recognition of our Uncertain Tax Position associated with a research and development tax credit of $0.4 million. There was no current income tax expense or benefit 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 20162020 primarily due to higher commodity prices, partially offset by lower production volumes. In the first nine monthsthird quarter of 2017,2021, as compared to the first nine monthsthird quarter of 2016,2020, oil production decreased 12%35%, natural gas production decreased 12%25%, and NGLs production decreased 7%23%. AverageThe decrease in volumes was due to normal well production declines and divestitures of producing properties which have not been offset by new drilling or acquisitions. Including derivatives settled, average oil prices increased 23%67% to $47.62$47.66 per barrel, average natural gas prices increased 26%125% to $2.50$2.88 per Mcf, and NGLs prices increased 68%over 200% to $17.05$27.42 per barrel.


Oil and natural gas operating costs increased $3.2decreased 0.8 million or 3% between the comparative first nine monthsthird quarters of 20172021 and 20162020 primarily due to higher LOE and grossthe settlement of Predecessor Period liabilities subject to compromise under the Plan offset by increased production tax partially offset by lower saltwater disposal expense.expenses due to increased revenues.


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$7.1 million or 44%58% in the first nine monthsthird quarter of 20172021 versus the first nine monthsthird quarter of 2016.2020. The increase was driven primarily by an increase in average number of rigs in use from 5.1 in the third quarter of 2020 to 11.0 in the third quarter of 2021.

Drilling operating costs increased $7.0 million or 83% between the comparative third quarters of 2021 and 2020. The change was primarily due primarily to a 78%an increase in the average number of drillingoperating rigs in use partially offset by a 11% decrease inand the average dayrate. Average drilling rig utilization increased from 16.7 drillingassociated start up costs bringing stacked 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.back into service.

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$40.6 million or 13%79% in the first nine monthsthird quarter of 20172021 as compared to the first nine monthsthird quarter of 20162020 primarily due primarily to increasedhigher gas, NGLs,NGL, and condensate prices, partially offset by a decrease in gas processedlower volumes. Gas processed volumes per day decreased 16%13% between the comparative periodsquarters primarily due to declines in existing volumes,connecting fewer new wells connected, and no offload volume atdeclining volumes on most of our Hemphill facility in 2017.major processing systems. Gas gathered volumes per day decreased 8%11% between the comparative periods primarilyquarters due declines in existingto declining volumes and fewer new wells connected, and no offload volume at our Hemphill facility in 2017.well connections.


Operating costs increased $12.743.1 million or 13%128% in the first nine monthsthird quarter of 20172021 compared to the first nine monthsthird quarter of 20162020 primarily due to increased purchasehigher gas, NGL, and condensate prices, partially offset by a decrease in gas purchasedlower purchase volumes. Depreciation and amortization decreased $1.9 million, or 5%, primarily due to certain assets being fully depreciated in 2017.

Other Depreciation

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


General and Administrative


Corporate general and administrative expenses increased $1.1decreased $2.7 million or 4%39% in the first nine monthsthird quarter of 20172021 as compared to the first nine monthsthird quarter of 20162020 primarily due to higher employee costs.

Gain on Dispositionreductions in payroll and benefits as well as the absence of Assets

There was an $1.2 million gain on disposition of assetsseparation benefits recognized in the first nine monthsthird quarter 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.2020.



Other Income (Expense)


Interest expense net of capitalized interest, decreased $1.4$2.1 million between the comparative first nine monthsthird quarters of 20172021 and 20162020 primarily due primarily to a 8%an 88% decrease in the average long-term debt outstanding, and increase interest capitalized partially offset by a higher average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized 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%3.7% in the third quarter of 2020 to 6.0%6.5% in the third quarter of 2021 and our average debt outstanding was $71.2decreased $137.2 million lower in the first nine monthsthird quarter of 2017 as2021 compared to the first nine monthsthird quarter of 20162020 primarily due to payments made under the decrease in outstandingExit credit agreement, partially offset by borrowings under ourthe Superior credit agreement overagreement.

Reorganization Items, Net

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


Gain (Loss)Loss on Derivatives


Gain (loss)Loss on derivatives increased $25.8by $39.4 million primarily due to fluctuationsincreases in forward prices used to estimate the fair value in mark-to-market accounting.

49
Table of Contents

Loss on Change in Fair Value of Warrants

Loss on change in fair value of warrants increased by $9.1 million primarily due to changes in the underlying assumptions used to estimate the fair value, including estimated strike price, entity value, duration to exercise and other inputs.

Income Tax Expense (Benefit)Benefit


We did not record an income tax benefit in the third quarter of 2021 compared to $4.8 million in the third quarter of 2020 due to the company's full valuation allowance against our net deferred tax asset. We paid no income taxes in the third quarter of 2021.


50
Table of Contents
Results of Operations
Nine Months Ended September 30, 2021 versus Nine Months Ended September 30, 2020
Provided below is a comparison of selected operating and financial data:
SuccessorSuccessorPredecessor
Percent
Change (1)
 Nine Months Ended September 30, 2021One Month Ended September 30, 2020Eight Months Ended August 31st, 2020
(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations$451,850 $35,342 $291,493 38 %
Total revenue, after inter-segment eliminations$418,202 $32,846 $276,957 35 %
Net loss$(13,511)$(6,736)$(890,624)99 %
Net income (loss) attributable to non-controlling interest$(4,875)$2,232 $40,388 (111)%
Net loss attributable to Unit Corporation$(8,636)$(8,968)$(931,012)99 %
Oil and Natural Gas:
Revenue, before inter-segment eliminations$181,003 $13,644 $103,443 55 %
Operating costs, before inter-segment eliminations$58,365 $6,892 $119,664 (54)%
Average oil price (Bbl)$47.77 $28.11 $32.02 51 %
Average oil price excluding derivatives (Bbl)$63.15 $36.94 $35.18 79 %
Average NGLs price (Bbl)$21.10 $7.47 $4.83 NM
Average NGLs price excluding derivatives (Bbls)$21.10 $7.47 $4.83 NM
Average natural gas price (Mcf)$2.87 $1.72 $1.14 139 %
Average natural gas price excluding derivatives (Mcf)$3.12 $1.70 $1.11 167 %
Oil production (MBbls)1,130 167 1,560 (35)%
NGLs production (MBbls)1,952 273 2,399 (27)%
Natural gas production (MMcf)21,750 2,849 26,561 (26)%
Contract Drilling:
Revenue, before inter-segment eliminations$52,893 $4,414 $73,519 (32)%
Operating costs, before inter-segment eliminations$41,308 $2,989 $51,811 (25)%
Average number of drilling rigs in use10.1 6.0 11.5 (7)%
Total drilling rigs available for use at the end of the period21 58 58 (64)%
Average dayrate on daywork contracts$17,944 $17,361 $18,911 (5)%
Mid-Stream:
Revenue, before inter-segment eliminations$217,954 $17,284 $114,531 65 %
Operating costs, before inter-segment eliminations$181,109 $12,130 $80,607 95 %
Gas gathered--Mcf/day300,484 345,460 388,506 (22)%
Gas processed--Mcf/day124,263 145,263 158,031 (21)%
Gas liquids sold--gallons/day431,474 473,371 612,301 (28)%
Number of natural gas gathering systems17 18 18 (6)%
Number of processing plants11 11 11 — %
Corporate and Other:
General and administrative expense, before inter-segment eliminations$15,406 $1,582 $42,766 (65)%
Other income (expense):
Interest expense, net$(3,895)$(826)$(22,882)(84)%
Write-off of debt issuance costs$— $— $(2,426)(100)%
Reorganization items, net$(3,959)$(1,155)$133,975 (103)%
Gain (loss) on derivatives$(104,973)$3,939 $(10,704)NM
Loss on change in fair value of warrants$(12,628)$— $— — %
Income tax benefit$— $— $(14,630)100 %
Average interest rate6.7 %5.9 %5.5 %21 %
Average long-term debt outstanding$57,815 $146,267 $526,167 (88)%
_________________________
1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
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Oil and Natural Gas

Oil and natural gas revenues increased $63.9 million or 55% in the first nine months of 2021 as compared to the first nine months of 2020 primarily due to higher commodity prices partially offset by lower production volumes. The decrease in volumes was due to normal well production declines and divestitures of producing properties which have not been offset by new drilling or acquisitions.

Oil and natural gas operating costs decreased 68.2 million or 54% between the comparative first nine months of 2021 and 2020 primarily due to the settlement of Predecessor Period liabilities subject to compromise under the Plan offset by increased production tax expenses due to increased revenues.

Contract Drilling

Drilling revenues decreased $25.0 million or 32% in the first nine months of 2021 versus the first nine months of 2020. The decrease was due primarily to lower rig termination and standby fees of $0.1 million in 2021 compared to $16.7 million in 2020. Additionally, there was a 7% decrease in the average number of drilling rigs in use and a 5% decrease in the average dayrate. Average drilling rig utilization decreased from 10.9 drilling rigs in the first nine months of 2020 to 10.1 drilling rigs in the first nine months of 2021.

Drilling operating costs decreased 13.5 million or 25% between the comparative first nine months of 2021 and 2020. The decrease was due primarily to the reduced number of drilling rigs operating.

Mid-Stream

Our mid-stream revenues increased $86.1 million or 65% in the first nine months of 2021 as compared to the first nine months of 2020 primarily due to higher prices, partially offset by lower volumes. Gas processed volumes per day decreased 21% between the comparative periods primarily due to declining volumes and fewer new wells connected to our processing systems. Gas gathered volumes per day decreased 22% between the comparative periods also due to declining volumes and fewer new wells connected to our gathering systems. We also experienced overall lower volumes due to the February 2021 winter storm.

Operating costs increased 88.4 million or 95% in the first nine months of 2021 compared to the first nine months of 2020 primarily due to higher gas, NGLs, and condensate prices, partially offset by lower purchase volumes.

General and Administrative

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

Other Income tax(Expense)

Interest expense increased $95.2decreased $19.8 million between the comparative first nine months of 20172021 and 20162020 primarily due to a reduction in average long-term debt outstanding, partially offset by a higher average interest rate. Our average interest rate increased pre-tax income. Our effective tax rate was 43.5% forfrom 5.5% in the first nine months of 2017 compared2020 to 34.8% for6.7% in the first nine months of 2016. The increase was2021 and our average debt outstanding decreased $426.8 million in the first nine months of 2021 compared to the first nine months of 2020 primarily due to the Notes being settled with the Plan and payments made under the Exit credit agreement.

Write-off of Debt Issuance Costs

Due to the termination of the remaining commitments of the Predecessor Period Unit credit agreement, unamortized debt issuance costs of $2.4 million were written off during the first nine months of 2020.

Reorganization Items, Net

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

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Loss on Derivatives

Loss on derivatives increased deferred tax expense relatedby $98.2 million primarily due to our restricted stock vestingsincreases in both comparative periods. There was no currentforward prices used to estimate the fair value in mark-to-market accounting.

Loss on Change in Fair Value of Warrants

Loss on change in fair value of warrants increased by $12.6 million primarily due to changes in the underlying assumptions used to estimate the fair value, including estimated strike price, entity value, duration to exercise and other inputs.

Income Tax Benefit

We did not record an income tax expense or benefit in the first nine months of 2017 or 2016.2021 compared to $14.6 million in the first nine months of 2020 due to the company's full valuation allowance against our net deferred tax asset. We did not pay anypaid no income taxes in the first nine 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 DisclosureDisclosures About Market Risk


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


Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas production. These prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our NGLs and natural gas production. Historically, these prices have fluctuated and we expect this to continue. The prices for oil, NGLs, and natural gas also affect the demand for our drilling rigs and the amount we can charge for the use of our drilling rigs. Based on our first nine months 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$0.3 million 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$0.1 million 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$0.2 million per month ($4.52.6 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 following2021, these derivatives were outstanding:
TermCommodityContracted Volume
Weighted Average 

Fixed Price
Contracted Market
Oct'17Oct'21 - Dec'21Natural gas –- basis swap70,00030,000 MMBtu/day$3.038(0.22)NGPL TEXOK
Oct'21Natural gas - swap50,000 MMBtu/day$2.82IF –- NYMEX (HH)
Nov’17 – Dec'17Nov'21 - Dec'21Natural gas –- swap60,00045,000 MMBtu/day$2.9602.90IF –- NYMEX (HH)
Jan’18 – Dec'18Jan'22 - Dec'22Natural gas –- swap20,0005,000 MMBtu/day$3.0132.61IF –- NYMEX (HH)
Nov’17 – Dec'17Jan'23 - Dec'23Natural gas – basis- swap20,00022,000 MMBtu/day$(0.215)2.46IF –- 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'17Oct'21 - Dec'21Natural gas – three-way collarCrude oil - swap25,000 MMBtu/3,373 Bbl/day$2.9045.14WTI - $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 September 30, 2021 would reduce our annual pre-tax cash flow by approximately $1.6less than $0.1 million. Under our Notes, we pay a fixed rateFor further information, see Note 9 – 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 Chief Financial Officer (CFO), does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) (Disclosure Controls) or our internal control over financial reporting (ICFR) (as defined in Rules 13a - 15(f) and 15d - 15(f) of the Exchange Act) will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part on certain assumptions about the likelihood of future events, and there is no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to an error or fraud may occur and not be detected. We monitor our Disclosure Controls and ICFR and make modifications as necessary; our intent in this regard is that the Disclosure Controls and ICFR will be modified as systems change, and conditions warrant.

Evaluation of Disclosure Controls and Procedures.As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive OfficerCEO and Chief Financial Officer,CFO, of the effectiveness of the design and operation of our disclosure controls and procedures under Exchange Act Rule 13a-15. Based on that evaluation, our Chief Executive OfficerCEO and Chief Financial OfficerCFO concluded that our disclosure controls and procedures arewere not effective as of September 30, 20172021 due to a material weakness in ensuringICFR 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 information is recorded, processed, summarizedknowledge 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 reported in our periodic SEC filings relatingprocedures were effective at June 30, 2020. This continued to be the company (including its consolidated subsidiaries)case as of September 30, 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 is accumulatedsupplementing internal resources with external expertise when appropriate.

We have also hired new personnel and communicatedre-assigned certain existing personnel into key positions. And we have conducted process improvement sessions with third party experts to enhance and augment business processes and utilization of system capabilities for greater effectiveness, efficiency, and scalability.

54
Our management believes 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 technologymeasures described above will remediate this material weakness and improve the timelinessoverall effectiveness of internal control over financial reporting. As management continues to evaluate and quality of our financial and operational information. This new ERP system was not implemented in response to any material weakness in ourimprove 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 controls operate for a sufficient period of time and management has affectedtested the processes that constitute parteffectiveness of our ICFRthose controls. Management expects these remedial actions and requires ongoing testing for effectiveness. The adoption of this new ERP system has not materially affected our ICFR.any other remedial actions related to the material weakness to be effectively implemented in 2021.

Changes in Internal Controls. There were no other changes in our ICFR during the quarter ended September 30, 2017,2021, that materially affected our ICFR or are reasonably likely to materially affect it, as defined in Rule 13a – 15(f) under the Exchange Act.


55
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 15 – 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, except as set forth below.


We areThe new OSHA rule requiring COVID-19 vaccination of employees could have a material adverse impact on our business and results of operations.

On November 4, 2021, OSHA released its interim final rule regarding the subjectBiden administration's vaccination mandate for employers with 100 or more employees. The rule was published in the Federal Register and became effective on November 5, 2021. As a company with more than 100 employees, the rule requires us, by January 4, 2022, to mandate COVID-19 vaccination of putative class action lawsuits that mayour workforce or require our unvaccinated employees to be tested weekly and wear a face covering while working. This could result in substantial expenditureshigher-than-normal employee turnover 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 believedifficulty satisfying future workforce needs. In that the allegations in these lawsuits are without merit and intend to defend such litigation vigorously, litigation is subject to inherent uncertainties, andcase, it could have an adverse result in one ofeffect on future revenues and costs, and, correspondingly, on future profit margins, which could be material. For these lawsuits or other matters that may arise from time to timereasons, the new rule could have a material adverse effect on our business and 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


On June 16, 2021, the company repurchased an aggregate of 600,000 shares of its common stock from the Lenders (as defined in Note 9 - Long-Term Debt and Other Long-Term Liabilities) which received these shares as an exit fee during the company’s reorganization. The Lenders were paid $15.00 per share for their respective shares, for an aggregate cash purchase price of $9.0 million.

In June 2021, the company's board of directors (the Board) authorized repurchasing up to $25.0 million of the company’s outstanding common stock. In October 2021, the Board authorized an increase from $25.0 million of authorized repurchases to $50.0 million. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. The company has no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice.

The following table provides information relating to our repurchase of common stockbelow represents all share repurchases for the three months ended September 30, 2017:2021:
PeriodTotal number of shares purchasedAverage price paid per shareTotal number of
shares purchased
as part of publicly
announced program
Approximate dollar
value of shares that
may yet be purchased
under the program (1)
(in thousands)
July 1, 2021 through July 31, 2021— $— — $25,000 
August 1, 2021 through August 31, 2021— $— — $25,000 
September 1, 2021 through September 30, 2021428,037 $25.31 350,037 $15,653 
1.Calculated as of September 30, 2021 without consideration to the subsequent increase in authorized repurchases described above.

Period
(a)
56
Total Number of Shares Purchased
(b)
Average Price Paid
Per Share
(c)
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs
(d)
Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
July 1, 2017 to July 31, 2017—
$—
—
—
August 1, 2017 to August 31, 2017—
—
—
—
September 1, 2017 to September 30, 2017—
—
—
—
Total—
$—
—
—

As of September 30, 2021, the company has repurchased a total of 350,037 shares at an average share price of $26.70 for an aggregate purchase price of $9.3 million under the repurchase program.

During the three months ended September 30, 2021, the company also repurchased 78,000 shares in a privately negotiation transaction at a share price of $19.07 outside of the repurchase program.

Subsequent to September 30, 2021, the company repurchased an additional 711,926 shares under the repurchase program at an average share price of $34.80 for an aggregate purchase price of $24.8 million bringing the aggregate shares repurchased under all methods since the Effective Date to 1,739,963 shares.

Item 3. Defaults Upon Senior Securities


Not applicable.


Item 4. Mine Safety Disclosures


Not applicable.



Item 5. Other Information


Not applicable.




57
Table of Contents
Item 6. Exhibits


Exhibits:
10.1
31.110.2
10.3
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.
104Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101)



58
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, 201712, 2021
By: /s/ Larry D. PinkstonPhilip B. Smith
LARRY D. PINKSTONPHILIP B. SMITH
President and Chief Executive Officer and Director
Date:November 2, 201712, 2021
By: /s/ David T. MerrillThomas D. Sell
DAVID T. MERRILLTHOMAS D. SELL
Chief Operating Officer, Chief Financial Officer
and Treasurer



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