Table of Contents

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[x]☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 20172022
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-20220630_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, 52,879,660August 11, 2022, 9,779,903 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
910
Item 2.
3035
Item 3.
5447
Item 4.
5648
PART II. Other Information
Item 1.
5649
Item 1A.
5749
Item 2.
5749
Item 3.
5749
Item 4.
5750
Item 5.
5850
Item 6.
5950
6051


1
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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 to utilize the benefits of net operating losses and other deferred tax assets against potential future taxable income;
•the number of gathering systems and processing plants weour mid-stream investment may plan to construct or acquire;
•volumes and prices for the natural gas gatheredour mid-stream investment gathers and processed;processes;
•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 mid-stream investment's ability to transport or convey our oil, NGLs, or natural gas production to establishedexisting pipeline systems;
•the impact of federal and state legislative and regulatory actions affecting our costs and increasing operating restrictions or delays and other adverse impacts on our business;
•the possibility of security threats, including terrorist attacks and cybersecurity breaches, against or otherwise affecting our facilities and systems;
•any projected production guidelines for the year;we may issue;
•our anticipated capital budgets;
•our financial condition and liquidity;
•the number of wells our oil and natural gas segment plans to drill or rework during the year;drill; 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.
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These statements are based on our assumptions and analyses made by us based onconsidering 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 risks and uncertainties are:
•the risk factors discussed in this document and in the documents (if any) we incorporate by reference;
•general economic, market, or business conditions;
•the availability of and nature of (or lack of) business opportunities we pursue;
•demand for our land drilling services;
•changes in laws orand regulations;
•changes in the current geopolitical situation;situation, such as the current conflict occurring between Russia and Ukraine;
•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•the amount and divert management's attention;terms of our debt;
•future compliance with covenants under our credit agreements;
•pandemics, epidemics, outbreaks, or other public health events, such as COVID-19; 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)
June 30,
2022		December 31,
2021
 (In thousands)
ASSETS
Current assets:
Cash and cash equivalents$115,628 $64,140 
Accounts receivable, net of allowance for credit losses of $2,355 and $2,511 as of June 30, 2022 and December 31, 2021, respectively69,268 87,248 
Prepaid expenses and other2,467 5,542 
Total current assets187,363 156,930 
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties224,462 225,014 
Unproved properties not being amortized2,194 422 
Drilling equipment70,062 66,058 
Gas gathering and processing equipment— 274,748 
Transportation equipment2,024 4,550 
Other8,645 8,631 
307,387 579,423 
Less accumulated depreciation, depletion, amortization, and impairment88,133 128,880 
Net property and equipment219,254 450,543 
Equity method investment (Note 15)1,658 — 
Right of use asset (Note 14)7,362 12,445 
Other assets6,755 9,559 
Total assets (1)
$422,392 $629,477 
1.Unit Corporation no longer consolidates the balance sheet of Superior Pipeline Company, L.L.C. (Superior) as of June 30, 2022, as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment. Unit Corporation's consolidated total assets as of December 31, 2021 included current and long-term assets of Superior of $61.1 million and $229.5 million, respectively, which can only be used to settle obligations of Superior. Unit Corporation's consolidated cash and cash equivalents of $64.1 million as of December 31, 2021 included $17.2 million held by Superior.
  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

June 30,
2022		December 31,
2021
 (In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable$31,718 $58,625 
Accrued liabilities (Note 8)20,422 22,450 
Current operating lease liability (Note 14)1,571 3,791 
Current derivative liabilities (Note 12)48,844 40,876 
Warrant liability (Note 12)— 19,822 
Current portion of other long-term liabilities (Note 9)5,009 5,574 
Total current liabilities107,564 151,138 
Long-term debt (Note 9)— 19,200 
Non-current derivative liabilities (Note 12)17,231 17,855 
Operating lease liability (Note 14)5,853 8,677 
Other long-term liabilities (Note 9)31,376 32,939 
Commitments and contingencies (Note 16)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; 12,028,561 shares issued and 9,831,169 outstanding at June 30, 2022, and 12,000,000 shares issued and 10,050,037 outstanding at December 31, 2021120 120 
Treasury stock (Note 5)(65,241)(51,965)
Capital in excess of par value251,202 198,171 
Retained earnings74,287 41,071 
Total shareholders’ equity attributable to Unit Corporation260,368 187,397 
Non-controlling interests in consolidated subsidiaries— 212,271 
Total shareholders' equity260,368 399,668 
Total liabilities and shareholders’ equity (1)
$422,392 $629,477 
1.Unit Corporation no longer consolidates the balance sheet of Superior as of June 30, 2022, as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment. Unit Corporation's consolidated total liabilities as of December 31, 2021 included current and long-term liabilities of Superior of $42.3 million and $21.2 million, respectively. All of Unit Corporation's consolidated long-term debt of $19.2 million as of December 31, 2021 was held by Superior.
  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


















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

5

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

Three Months Ended June 30,Six Months Ended June 30, 2022
 2022202120222021
(In thousands except per share amounts)
Revenues:
Oil and natural gas$100,912 $41,970 $177,722 $96,994 
Contract drilling33,642 18,061 62,524 33,735 
Gas gathering and processing— 74,026 82,673 124,225 
Total revenues134,554 134,057 322,919 254,954 
Expenses:
Operating costs:
Oil and natural gas27,619 15,487 51,094 34,636 
Contract drilling25,763 14,080 52,000 25,951 
Gas gathering and processing— 45,056 62,388 84,719 
Total operating costs53,382 74,623 165,482 145,306 
Depreciation, depletion, and amortization5,661 16,364 16,931 33,875 
General and administrative7,421 5,751 13,947 12,920 
Gain on disposition of assets (Note 4)(2,066)(1,710)(4,241)(2,182)
Total operating expenses64,398 95,028 192,119 189,919 
Income from operations70,156 39,029 130,800 65,035 
Other income (expense):
Interest, net(97)(487)(371)(3,193)
Gain (loss) on derivatives (Note 12)2,609 (42,400)(61,467)(65,231)
Gain (loss) on change in fair value of warrants (Note 12)7,289 (3,574)(29,323)(3,574)
Loss on deconsolidation of Superior (Note 15)— — (13,141)— 
Reorganization items, net(39)(1,852)(42)(2,988)
Other, net175 (831)932 (755)
Total other income (expense)9,937 (49,144)(103,412)(75,741)
Income (loss) before income taxes80,093 (10,115)27,388 (10,706)
Income tax expense (benefit):
Current— — — — 
Deferred— — — — 
Total income taxes— — — — 
Net income (loss)80,093 (10,115)27,388 (10,706)
Net income (loss) attributable to non-controlling interest (Note 15)— 2,879 (5,828)4,225 
Net income (loss) attributable to Unit Corporation$80,093 $(12,994)$33,216 $(14,931)
Net income (loss) attributable to Unit Corporation per common share (Note 7):
Basic$7.99 $(1.09)$3.31 $(1.25)
Diluted$7.82 $(1.09)$3.25 $(1.25)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
  (In thousands except per share amounts)
Revenues:        
Oil and natural gas $85,470
 $78,854
 $256,241
 $206,318
Contract drilling 51,619
 25,819
 128,059
 88,786
Gas gathering and processing 51,399
 48,735
 150,493
 132,793
Total revenues 188,488
 153,408
 534,793
 427,897
Expenses:        
Operating costs:        
Oil and natural gas 33,911
 26,014
 95,873
 92,691
Contract drilling 34,747
 19,137
 91,213
 66,489
Gas gathering and processing 38,116
 35,738
 111,862
 99,185
Total operating costs 106,774
 80,889
 298,948
 258,365
Depreciation, depletion, and amortization 54,533
 49,969
 151,545
 158,437
Impairments (Note 2) —
 49,443
 —
 161,563
General and administrative 9,235
 8,852
 26,902
 25,811
Gain on disposition of assets (81) (154) (1,153) (823)
Total operating expenses 170,461
 188,999
 476,242
 603,353
Income (loss) from operations 18,027
 (35,591) 58,551
 (175,456)
Other income (expense):        
Interest, net (9,944) (10,002) (28,807) (30,225)
Gain (loss) on derivatives (2,614) 6,969
 21,019
 (4,774)
Other, net 5
 3
 14
 (11)
Total other income (expense) (12,553) (3,030) (7,774) (35,010)
Income (loss) before income taxes 5,474
 (38,621) 50,777
 (210,466)
Income tax expense (benefit):        
Deferred 1,769
 (14,599) 22,084
 (73,159)
Total income taxes 1,769
 (14,599) 22,084
 (73,159)
Net income (loss) $3,705
 $(24,022) $28,693
 $(137,307)
Net income (loss) per common share:        
Basic $0.07
 $(0.48) $0.56
 $(2.75)
Diluted $0.07
 $(0.48) $0.56
 $(2.75)









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

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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)CHANGES IN SHAREHOLDERS’ EQUITY (UNAUDITED)

Shareholders' Equity Attributable to Unit Corporation
Common
Stock		Treasury
Stock		Capital in Excess
of Par Value		Retained
Earnings (Deficit)		Non-controlling Interest in Consolidated SubsidiariesTotal
 (In thousands)
Balances as of December 31, 2021$120 $(51,965)$198,171 $41,071 $212,271 $399,668 
Net loss— — — (46,877)(5,828)(52,705)
Distributions to non-controlling interests— — — — (9,479)(9,479)
Deconsolidation of Superior— — — — (196,964)(196,964)
Activity in stock-based compensation plans— — 1,038 — — 1,038 
Balances as of March 31, 2022$120 $(51,965)$199,209 $(5,806)$— $141,558 
Net income— — — 80,093 — 80,093 
Activity in stock-based compensation plans— — 2,848 — — 2,848 
Repurchases of common stock— (13,276)— — — (13,276)
Warrant liability reclassification— — 49,145 — — 49,145 
Balances as of June 30, 2022$120 $(65,241)$251,202 $74,287 $— $260,368 
 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)


Shareholders' Equity Attributable to Unit Corporation
Common
Stock		Treasury
Stock		Capital in Excess
of Par Value		Retained
Earnings (Deficit)		Non-controlling Interest in Consolidated SubsidiariesTotal
 (In thousands)
Balances as of December 31, 2020$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 as of March 31, 2021$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)
Repurchases of common stock— (9,048)— — — (9,048)
Balances as of June 30, 2021$120 $(9,048)$197,561 $(33,071)$238,283 $393,845 











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)
 Six Months Ended June 30, 2022
 20222021
(In thousands)
OPERATING ACTIVITIES:
Net income (loss)$27,388 $(10,706)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization16,931 33,875 
Loss on derivatives (Note 12)61,467 65,231 
Cash payments on derivatives settled (Note 12)(54,123)(9,707)
Loss on change in fair value of warrants (Note 12)29,323 3,574 
Loss on deconsolidation of Superior (Note 15)13,141 — 
Gain on disposition of assets (Note 4)(4,241)(2,182)
Stock-based compensation plans (Note 6)3,886 350 
Change in credit loss reserve(156)482 
ARO liability accretion (Note 10)974 931 
Contract assets and liabilities, net (Note 3)83 1,584 
Noncash reorganization items(77)433 
Other, net(673)(1,009)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable(23,090)(6,336)
Prepaid expenses and other2,288 2,536 
Accounts payable8,119 (2,279)
Accrued liabilities7,079 (3,852)
Income taxes(178)1,116 
Contract advances(16)(76)
Net change in operating assets and liabilities(5,798)(8,891)
Net cash provided by operating activities88,125 73,965 
INVESTING ACTIVITIES:
Capital expenditures(16,474)(7,673)
Deconsolidation of Superior cash and cash equivalents (Note 15)(10,119)— 
Proceeds from disposition of property and equipment (Note 4)12,711 15,278 
Net cash provided by (used in) investing activities(13,882)7,605 
FINANCING ACTIVITIES:
Borrowings under line of credit (Note 9)— 3,900 
Payments under line of credit (Note 9)— (67,900)
Net payments on finance leases (Note 14)— (3,216)
Distributions to non-controlling interests (Note 15)(9,479)(12,344)
Repurchases of common stock (Note 5)(13,276)(9,048)
Bank overdrafts— 1,313 
Net cash used in financing activities(22,755)(87,295)
Net increase (decrease) in cash and cash equivalents51,488 (5,725)
Cash and cash equivalents, beginning of period64,140 12,714 
Cash and cash equivalents, end of period$115,628 $6,989 
  Nine Months Ended
  September 30,
  2017 2016
  (In thousands)
OPERATING ACTIVITIES:    
Net income (loss) $28,693
 $(137,307)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation, depletion, and amortization 151,545
 158,437
Impairments (Note 2) —
 161,563
Amortization of debt issuance costs and debt discount (Note 6) 1,616
 1,586
(Gain) loss on derivatives (21,019) 4,774
Cash (payments) receipts on derivatives settled, net (729) 11,735
Deferred tax expense (benefit) 22,084
 (73,159)
Gain on disposition of assets (1,153) (1,100)
Stock compensation plans 12,478
 10,664
Other, net 1,397
 (3,055)
Changes in operating assets and liabilities increasing (decreasing) cash:    
Accounts receivable (36,381) 759
Accounts payable 4,873
 26,940
Material and supplies 17
 231
Accrued liabilities��20,280
 14,073
Income taxes (15) 20,636
Other, net 1,106
 985
Net cash provided by operating activities 184,792
 197,762
INVESTING ACTIVITIES:    
Capital expenditures (167,392) (154,558)
Producing properties and other acquisitions (Note 3) (55,429) —
Proceeds from disposition of assets 20,137
 46,880
Other (1,500) 169
Net cash used in investing activities (204,184) (107,509)
FINANCING ACTIVITIES:    
Borrowings under credit agreement 251,401
 195,700
Payments under credit agreement (250,100) (261,700)
Payments on capitalized leases (2,967) (2,756)
Proceeds from common stock issued, net of issue costs (Note 13) 18,623
 —
Tax benefit from stock compensation —
 (376)
Book overdrafts 2,364
 (21,043)
Net cash provided by (used in) financing activities 19,321
 (90,175)
Net increase (decrease) in cash and cash equivalents (71) 78
Cash and cash equivalents, beginning of period 893
 835
Cash and cash equivalents, end of period $822
 $913




Supplemental disclosure of cash flow information:    
Cash paid during the year for:    
Interest paid (net of capitalized) 14,601
 16,650
Income taxes —
 —
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment (20,122) 36,934
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations (3,203) 29,423




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

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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - CONTINUED

 Six Months Ended June 30, 2022
 20222021
 (In thousands)
Supplemental disclosure of cash flow information:
Cash paid (received) for:
Interest paid$456 $3,764 
Income taxes178 (1,116)
Reorganization items35 2,554 
Changes in accounts payable and accrued liabilities related to purchases of property and equipment(1,840)(3,318)
Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations(1,427)1,115 
Non-cash trade of property and equipment30 — 







































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 subsidiariessubsidiaries. References to our mid-stream segment refer to Superior Pipeline Company, L.L.C. (Superior) of which we own 50%.

We are primarily engaged in the development, acquisition, and affiliates, exceptproduction 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 primarily located in Oklahoma and Texas, and to a lesser extent, in Arkansas, Kansas, Louisiana, and North Dakota.

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 otherwise indicated orwell as the context otherwise requires.for our own account. Our drilling operations are primarily located in Oklahoma, Texas, New Mexico, Wyoming, and North Dakota.


The condensed consolidatedMid-Stream. Carried out by Superior of which we own 50%, buys, sells, gathers, transports, processes, and treats natural gas for UPC and for third parties. Mid-Stream operations are primarily located in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

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 (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, 2016.2021 included in the company’s Annual Report on Form 10-K as filed with the SEC on March 31, 2022.


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

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 date the financial statements are issued.

The unaudited condensed consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. We consolidated the financial position, operating results, and cash flows of Superior prior to be realized forMarch 1, 2022, on which date the full year of 2017, orMaster Services and Operating Agreement (MSA) was amended and restated, with the result that we realized for the full year of 2016.

Certain amounts inno longer consolidate Superior's financial position, operating results, and cash flows during periods subsequent to March 1, 2022. Accordingly, the unaudited condensed consolidated financial statements and notes reflect Superior activity on a consolidated basis for the two months prior to March 1, 2022. See Note 15 – Superior Investment for more information on the Superior investment and consolidation conclusions. All intercompany transactions and accounts between consolidated entities have been eliminated, including activity between Unit and Superior during the two months prior to March 1, 2022. Intercompany transactions and accounts between Unit and Superior subsequent to March 1, 2022 are not eliminated.

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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.


Recent Accounting Pronouncements

Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 and ASU 2021-01 which provide and clarify optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs 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. In April 2022, the FASB proposed to defer the effective date to December 31, 2024, but a final ruling has not been issued. We have not yet elected to use the optional guidance and continue to evaluate the options provided by ASU 2020-04 and ASU 2021-01.

NOTE 23 – OIL AND NATURAL GAS PROPERTIESREVENUE FROM CONTRACTS WITH CUSTOMERS

Full cost accounting rules require us to reviewOur 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 in Note 19 – Industry Segment Information. Revenue from the carrying valueoil and natural gas segment is from sales of our oil and natural gas propertiesproduction. Revenue from the contract drilling segment comes from contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period. Revenues from the mid-stream segment are generated from the fees earned for gas gathering and processing services provided to a customer or by selling of hydrocarbons to other mid-stream companies.

Oil and Natural Gas Revenue

Typical types of revenue contracts entered into by our oil and gas segment are Oil Sales Contracts, North American Energy Standards Board (NAESB) Contracts, Gas Gathering and Processing Agreements, and revenues earned as the non-operated party with the operator serving as an agent on our behalf under joint operating agreements. Consideration received is variable and settled monthly while contract terms can range from a single month or evergreen to terms of a decade or more. Revenues from oil and natural gas sales are recognized when the customer obtains control of the sold product which typically occurs at the endpoint of each quarter. Under those rules,delivery to the maximum amount allowedcustomer.

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)commodity is transferred to our customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing and transportation costs are included as part of the estimated future net revenues from our proved reserves (usingcontract price with the unescalated 12-month average pricecustomer on transfer of our oil, NGLs, and natural gas), pluscontrol of the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved propertiescommodity are included in the transaction price, while costs being amortized,incurred while we are in control of the commodity represent operating costs.

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Contract Drilling Revenue

Contract drilling revenues and expenses are primarily recognized as services are performed and collection is reasonably assured. Payments for mobilization and demobilization activities do not relate to a distinct good or service within the contract and are deferred for ratable recognition when material. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred and any reimbursements received for out-of-pocket expenses are recorded as both revenues and direct costs.

Most of our drilling contracts have a term of one year or less and the remaining performance obligations under the contracts without a fixed term are not material.

Mid-Stream Revenue

The typical revenue contracts used by this segment are gas gathering and processing agreements as well as product sales. Superior recognizes sales revenue at the point in time when control transfers to the purchaser, typically at a specified delivery point, based on the contractually agreed upon fixed or index-based price received. Contracts for gas gathering and processing services may include terms for demand fees or shortfall fees. Demand fees or shortfall fees exist in arrangements where a customer agrees to pay a fixed fee for a contractually agreed upon pipeline capacity or shortfall fees for any minimum volumes not utilized, which create performance obligations for each individual period of reservation. Revenue for these fees is recognized once the services have been completed, the customer no longer has access to the contracted capacity, or the likelihood of the customer exercising all or a portion of their remaining rights becomes remote.

Contract Assets and Liabilities

The table below shows the changes in our contract asset and contract liability balances during periods presented:

Classification on the unaudited condensed consolidated balance sheetsJune 30,
2022		December 31,
2021		Change
(In thousands)
Assets
Current contract assetsPrepaid expenses and other$— $174 $(174)
Non-current contract assetsOther assets— — — 
Total contract assets$— $174 $(174)
Liabilities
Current contract liabilitiesCurrent portion of other long-term liabilities$560 $1,588 $(1,028)
Non-current contract liabilitiesOther long-term liabilities188 200 (12)
Total contract liabilities748 1,788 (1,040)
Contract assets (liabilities), net$(748)$(1,614)$866 

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NOTE 4 – DIVESTITURES

Oil and Natural Gas

The company initiated an asset divestiture program at the 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 was expanding the Divestiture Program to include the potential sale of additional properties, including up to all of UPC’s oil and gas properties and reserves, and on January 20, 2022, the company announced that it had retained a financial advisor and launched the process. On June 10, 2022, the company announced that it had ended its engagement with the financial advisor and terminated the process. During the process, the Company entered into an agreement to sell its Texas Gulf Coast oil and gas properties.

On July 1, 2022, the company closed on the sale of certain wells and related income taxes. Ifleases near the Texas Gulf Coast for cash proceeds of $43.7 million, subject to customary post-closing adjustments based on an effective date of April 1, 2022. These proceeds will reduce the net book value of our full cost pool with no gain or loss recognized as the oil, NGLs, and natural gas properties being amortized exceedssale did not result in a significant alteration of the full cost ceiling,pool.

On March 8, 2022, the excess amount is charged to expense incompany closed on the period during whichsale of certain non-core wells and related leases located near the excess occurs, even if prices are depressedOklahoma Panhandle for only a short while. Once incurred, a write-downcash proceeds 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$4.1 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 closedcustomary closing and post-closing adjustments based 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 acres 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 one gathering system as part of the transaction.

We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations, which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the adjusted purchase price 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 are subject to change as additional information becomes available and is assessed by us (in thousands):
Adjusted Purchase Price 
Total consideration given$54,332
  
Adjusted Allocation of Purchase Price 
Oil and natural gas properties included in the full cost pool: 
Proved oil and natural gas properties$43,745
Undeveloped oil and natural gas properties8,650
Total oil and natural gas properties included in the full cost pool (1)
52,395
Gas gathering equipment and other2,340
Asset retirement obligation(403)
Fair value of net assets acquired$54,332
(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.
The pro forma effects of this acquired business is immaterial to the results of operations.

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

Divestitures

We sold non-core oil and natural gas assets, net of related expenses, for $18.0 million during the first nine months of 2017, compared to $43.6 million during the first nine months of 2016. Proceeds from those salesDecember 1, 2021. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.recognized as the sale did not result in a significant alteration of the full cost pool.


On May 6, 2021, the company closed on the sale of substantially all of our wells and the leases related thereto located in Reno and Stafford Counties, Kansas for proceeds of $7.1 million, excluding post-closing adjustments. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool.

Net proceeds for the sale of other non-core oil and natural gas assets totaled $1.9 million and $2.7 million during the three months ended June 30, 2022 and 2021, respectively, and $2.3 million and $4.4 million during the six months ended June 30, 2022 and 2021, respectively. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sales did not result in a significant alteration of the full cost pool.

Contract Drilling

Proceeds for the sale of non-core contract drilling assets totaled $4.2 million and $1.9 million during the three months ended June 30, 2022 and 2021, respectively, and $6.4 million and $3.9 million during the six months ended June 30, 2022 and 2021, respectively. These proceeds resulted in net gains of $2.0 million and $1.6 million during the three months ended June 30, 2022 and 2021, respectively, and $4.2 million and $2.1 million during the six months ended June 30, 2022 and 2021, respectively. The net gains are presented within gain on disposition of assets in the unaudited condensed consolidated statements of operations.

NOTE 45 – CAPITAL STOCK

Stock Repurchases

In June 2021, we repurchased an aggregate of 600,000 shares of our 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 our 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. The Board subsequently authorized increases to the authorized repurchases up to $50.0 million in October 2021 and then up to $100.0 million in June 2022. 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 June 30, 2022, we had repurchased a total of 1,519,392 shares under the repurchase program at an average share price of $36.00 for an aggregate purchase price of $54.7 million. Subsequent to June 30, 2022, we have repurchased an additional 75,000 shares under the repurchase program for an aggregate purchase price of $3.8 million.

During the year ended December 31, 2021, we also repurchased 78,000 shares in a privately negotiated transaction at a share price of $19.07 which were not part of the repurchase program.
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The cumulative number of shares repurchased as of June 30, 2022 totaled 2,197,392. The cash purchase price and any direct acquisition costs are reflected as treasury stock on the unaudited condensed consolidated balance sheets as of June 30, 2022.

Warrants

Each holder of Unit common stock outstanding (Old Common Stock) before the September 3, 2020 emergence from bankruptcy (Emergence Date) that did not opt out of the release under the Chapter 11 plan of reorganization filed with the bankruptcy court on June 9, 2020 is entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant is exercisable for one share of common stock, subject to adjustment as provided in the Warrant Agreement. The warrants expire on the earliest of (i) September 3, 2027, (ii) consummation of a Cash Sale (as defined in the Warrant Agreement), or (iii) the consummation of a liquidation, dissolution or winding up of the company. As of June 30, 2022, the company had issued 1,822,203 warrants.

Among other provisions, the Warrant Agreement outlines potential adjustments to the warrants if certain events occur, including (i) stock dividends payable in shares of common stock or stock splits, (ii) reverse stock splits or similar combination events, (iii) Liquidity Events (as defined in the Warrant Agreement), and (iv) other events not explicitly contemplated which may have an adverse impact to the intent and purpose of the warrants as set forth in the Plan, provided, however, the warrants will not be adjusted for (a) any issuances of securities in connection with a merger, share exchange, asset acquisition, stock purchase, recapitalization, reorganization or other similar business combination, (b) the issuance of any securities by Unit on or after the Effective Date (as defined in the Plan) pursuant to the Plan or upon the issuance of shares of common stock upon the exercise of such securities, (c) the issuance of any shares of common stock pursuant to the exercise of the warrants, (d) the issuance of shares of common stock pursuant to any management stock option incentive or similar plan, (e) a dividend or distribution to holders of common stock of cash, property, or securities (other than common stock), and/or (f) any change in the par value of the common stock.

Pursuant to the terms of the Warrant Agreement, the company determined the initial exercise price of the warrants to be $63.74. On April 7, 2022, the company delivered notice of the initial exercise price to the Warrant Agent and the warrants became exercisable for shares of the company’s common stock. On or about April 25, 2022, the warrants began trading over-the-counter under the symbol "UNTCW".

See Note 12 - Derivatives for more information on how the warrants are treated in our unaudited condensed consolidated financial statements.

NOTE 6 – STOCK-BASED COMPENSATION

On the Effective Date, the Board adopted the Unit Corporation Long Term Incentive Plan (LTIP) to incentivize employees, officers, directors and other service providers of the company and its affiliates. The LTIP will be administered by the Board or a committee thereof and 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 (RSUs), 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 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.
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The table below summarizes the stock-based compensation expense activity recognized during the following periods:

Three Months Ended June 30,Six Months Ended June 30,
2022202120222021
(In thousands)
Recognized stock compensation expense$2,847 $216 $3,885 $216 
Capitalized stock compensation cost for our oil and natural gas properties— — — — 
Tax benefit on stock-based compensation$697 $53 $952 $53 

The tables below summarize the activity pertaining to nonvested RSUs during the three and six months ended June 30, 2022 and 2021:

Three Months Ended June 30,
20222021
Number
of Shares
Weighted
Average Grant Date
Fair Value
Number
of Shares
Weighted
Average Grant Date
Fair Value
Nonvested RSUs, beginning of period322,855 $26.80 — $— 
Granted— — 109,008 12.90 
Vested(28,037)13.39 — — 
Forfeited— — — — 
Nonvested RSUs, end of period294,818 $28.07 109,008 $12.90 

Six Months Ended June 30,
20222021
Number
of Shares
Weighted
Average Grant Date
Fair Value
Number
of Shares
Weighted
Average Grant Date
Fair Value
Nonvested RSUs, beginning of period315,529 $26.71 — $— 
Granted (1)
7,850 30.50 109,008 12.90 
Vested(28,561)13.71 — — 
Forfeited— — — — 
Nonvested RSUs, end of period (2)
294,818 $28.07 109,008 $12.90 
1.RSUs granted in January 2022 had an aggregate grant date fair value of $0.2 million and vest equally each month for thirty months. RSUs granted in April 2021 had an aggregate grant date fair value of $1.4 million and vest 25% on each of the following dates: May 27, 2022, September 3, 2022, September 3, 2023, and September 3, 2024.
2.The aggregate compensation cost related to nonvested RSUs not yet recognized as of June 30, 2022 was $5.6 million with a weighted average remaining service period of 1.3 years.

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The tables below summarize the activity pertaining to outstanding stock options during the three and six months ended June 30, 2022 and 2021:

Three Months Ended June 30,
20222021
Number
of Shares
Weighted Average
Exercise Price
Number
of Shares
Weighted Average
Exercise Price
Outstanding stock options, beginning of period374,834 $45.00 — $— 
Granted— — — — 
Exercised— — — — 
Forfeited or expired— — — — 
Outstanding stock options, end of period374,834 $45.00 — $— 

Six Months Ended June 30,
20222021
Number
of Shares
Weighted Average
Exercise Price
Number
of Shares
Weighted Average
Exercise Price
Outstanding stock options, beginning of period361,418 $45.00 — $— 
Granted (1)
13,416 45.00 — — 
Exercised— — — — 
Forfeited or expired— — — — 
Outstanding stock options, end of period (2)
374,834 $45.00 — $— 
1.Stock options granted in January 2022 had an aggregate grant date fair value of $0.1 million and 100% vest on the first anniversary of the grant date.
2.Stock options outstanding as of June 30, 2022 had a weighted average remaining contractual term of 4.2 years and an aggregate intrinsic value of $2.1 million. None of the stock options outstanding as of June 30, 2022 were exercisable. The aggregate compensation cost related to outstanding options not yet recognized as of June 30, 2022 was $2.6 million with a weighted average remaining service period of 1.2 years.

NOTE 7 – EARNINGS (LOSS) PER SHARE


Information related toThe tables below show the calculation of earnings (loss)loss per share follows:attributable to Unit Corporation using the treasury stock method for the periods indicated:

  
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)
Earnings (Loss)
(Numerator)		Weighted
Shares
(Denominator)		Per-Share
Amount
 (In thousands except per share amounts)
Three months ended June 30, 2022
Basic earnings attributable to Unit Corporation per common share$80,093 10,025 $7.99 
Effect of dilutive restricted stock units and stock options (1)
— 223 (0.17)
Diluted earnings attributable to Unit Corporation per common share$80,093 10,248 $7.82 
Three months ended June 30, 2021
Basic loss attributable to Unit Corporation per common share$(12,994)11,901 $(1.09)
Effect of dilutive restricted stock units (2)
— — — 
Diluted loss attributable to Unit Corporation per common share$(12,994)11,901 $(1.09)


Due to the net loss1.The diluted earnings per share calculation for the three months ended SeptemberJune 30, 2016, approximately 546,000 weighted average shares2022 excludes the effects related to 1,822,203 average outstanding warrants with a $63.74 exercise price because their inclusion would be antidilutive.
2.The diluted loss per share calculation for the three months ended June 30, 2021 excludes the effect related to 77,863 average outstanding restricted stock units because their inclusion would be antidilutive.
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Earnings (Loss)
(Numerator)		Weighted
Shares
(Denominator)		Per-Share
Amount
 (In thousands except per share amounts)
Six months ended June 30, 2022
Basic earnings attributable to Unit Corporation per common share$33,216 10,037 $3.31 
Effect of dilutive restricted stock units and stock options (1)
— 189 (0.06)
Diluted earnings attributable to Unit Corporation per common share$33,216 10,226 $3.25 
Six months ended June 30, 2021
Basic loss attributable to Unit Corporation per common share$(14,931)11,950 $(1.25)
Effect of dilutive restricted stock units (2)
— — — 
Diluted loss attributable to Unit Corporation per common share$(14,931)11,950 $(1.25)
1.The diluted earnings per share calculation for the six months ended June 30, 2022 excludes the effects related to 361,418 average outstanding stock options with a $45.00 exercise price and 1,822,203 average outstanding warrants with a $63.74 exercise price because their inclusion would be antidilutive.
2.The diluted loss per share calculation for the six months ended June 30, 2021 excludes the effect related to 39,147 average outstanding restricted stock and SARs were antidilutive and excluded from the calculation above.

The following table shows the number of stock options and SARs (and their average exercise price) excludedunits because their option exercise prices were greater than the average market price of our common stock:inclusion would be antidilutive.

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

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

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

The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
  Nine Months Ended
  September 30,
  2017 2016
Stock options and SARs 178,755
 240,270
Average exercise price $47.75
 $49.29

NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of:
  September 30,
2017		 December 31,
2016
  (In thousands)
Interest payable $17,480
 $6,524
Employee costs 14,526
 15,394
Lease operating expenses 12,686
 10,075
Taxes 9,982
 2,219
Third-party credits 2,184
 2,998
Other 3,274
 2,441
Total accrued liabilities $60,132
 $39,651

NOTE 68 – ACCRUED LIABILITIES

The table below provides detail on our accrued liabilities as of the dates indicated:

June 30,
2022		December 31,
2021
 (In thousands)
Employee costs$11,565 $10,005 
Lease operating expenses3,735 3,451 
Capital expenditures1,658 3,962 
Taxes2,315 3,320 
Interest payable97 296 
Other1,052 1,416 
Total accrued liabilities$20,422 $22,450 
NOTE 9 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES


Long-Term Debt


OurThe table below provides detail on our outstanding long-term debt as of the dates indicated consistedindicated:

June 30,
2022		December 31,
2021
(In thousands)
Long-term debt:
Exit credit agreement$— $— 
Superior credit agreement (1)
$19,200 
1.Unit Corporation no longer consolidates the balance sheet of Superior as of June 30, 2022, as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment.

Exit Credit Agreement. On the Effective Date, under the terms of the following:
  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 scheduled to mature on April 10, 2020. UnderPlan, 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 amount we can borrow iscompany, UDC, and UPC (together, the lesserBorrowers), (ii) the guarantors party thereto, including the company and all of its subsidiaries existing as of the amount we elect as the commitment amount or the value of the borrowing base as determined byEffective Date (other than Superior and its subsidiaries), (iii) the lenders but in either event notparty thereto from time to exceed $875.0 million. Our borrowing basetime (Lenders), and elected commitment is $475.0 million. We are charged a commitment fee(iv) BOKF, NA dba Bank of 0.50% onOklahoma as administrative agent and collateral agent (in such capacity, the amount available but not borrowed. That fee varies based onAdministrative Agent).

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On April 6, 2021, the amount borrowed as a percentage ofcompany finalized the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees overfirst amendment to the life of theExit credit agreement. Under the first amendment, the company reaffirmed its borrowing base of $140.0 million of the RBL Facility, 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.

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.

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 Facility 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.

On March 30, 2022, the RBL Facility borrowing base of $80.0 million was reaffirmed.

On July 1, 2022, the RBL Facility borrowing base was automatically reduced to $31.3 million as a result of closing the Texas Gulf Coast properties sale discussed in Note 4 - Divestitures.

The maturity date of borrowings under this Exit credit agreement we pledgedis March 1, 2024. Revolving Loans and Term Loans (each as defined in the following collateral: (a) 85%Exit credit agreement) may be Eurodollar Loans or ABR Loans (each as defined in the Exit credit agreement). Revolving Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate (as defined in the Exit credit agreement) for the applicable interest period plus 525 basis points. Revolving Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate (as defined in the Exit credit agreement) plus 425 basis points. Term Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate for the applicable interest period plus 625 basis points. Term Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate plus 525 basis points.

The Exit credit agreement requires the company to comply with certain financial ratios, including a covenant that the company will not permit the Net Leverage Ratio (as defined in the Exit credit agreement) as of the 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 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 percentagelast day of the discounted future value of our oilfiscal quarters ended (i) December 31, 2020 and natural gas reserves. The October 2017 redetermination didMarch 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 result(a) permit the Current Ratio (as defined in any changes. We or the lenders may request a onetime special redeterminationExit credit agreement) as of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination followinglast day of any fiscal quarter to be less than 1.00 to 1.00 or (b) permit the completion of an acquisition that meets the requirementsInterest Coverage Ratio (as defined in the Exit credit agreement.

At our election, any partagreement) as of the outstanding debt under thelast day of any fiscal quarter to be less than 2.50 to 1.00. The Exit credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed asalso contains provisions, among others, that limit certain capital expenditures, and require certain hedging activities. The Exit credit agreement further requires the LIBOR base for the term plus 2.00%company to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable atprovide quarterly financial statements within 45 days after the end of each term, or everyof the first three quarters of each fiscal year and annual financial statements within 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 atafter the end of each monthfiscal year. As of June 30, 2022, 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 principal may be repaidGuarantors, including the company’s ownership interests in whole or in part at any time, without a premium or penalty. At SeptemberSuperior.

As of June 30, 2017,2022, we had $162.1no long-term borrowings and $2.4 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.outstanding under the Exit credit agreement.


Superior Credit Agreement. On May 10, 2018, Superior entered into a five-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions (Superior credit agreement). The amounts borrowed under the Superior credit agreement prohibits, among other things:

bore annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the paymentapplicable margin of dividends (other than stock dividends) during any fiscal year over 30%2.00% to 3.25% or (b) the alternate base rate (greater of our consolidated net income for(i) the preceding fiscal year;
federal funds rate plus 0.5%, (ii) the incurrence of additional debt with certain limited exceptions;prime rate, and
(iii) 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 ratioThirty-Day LIBOR Rate (as defined in the Superior credit agreement)) plus the applicable margin of not less than 11.00% to 1.2.25%.


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

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

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

a leverage ratio of funded debt to consolidatedConsolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quartersratio of nonot greater than 44.00 to 1.

As1.00. The agreement also contained 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 September 30, 2017, we wereassets. Superior was in compliance with these covenants as of June 30, 2022.
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On April 29, 2022, Superior entered into an Amended and Restated Credit Agreement for a four-year, $135.0 million senior secured revolving credit facility with an option to increase the credit agreement covenants.

6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0up to $200.0 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(Amended Superior credit agreement). The amounts borrowed under the Amended Superior credit agreement bear annual interest at a purchase price in cashrate, at Superior’s option, equal to 101%(a) SOFR plus the applicable margin of 2.75% to 3.75% or (b) the principal amountalternate base rate (greater of (i) the Notesfederal funds rate plus accrued0.5%, (ii) the prime rate, and unpaid interest to(iii) SOFR plus 0.10%). The obligations under 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 ofAmended Superior credit agreement are secured by, among other things, mortgage liens on certain of our subsidiariesSuperior’s processing plants and gathering systems. Unit is not a party to and does not guarantee the Amended Superior credit agreement.

The Amended Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 3.50 to 1.00. Additionally, the Amended Superior credit agreement contains a number of customary covenants that, among other things, restrict (subject to certain exceptions) Superior’s ability to incur or guarantee additional indebtedness;indebtedness, create additional liens on its assets, make investments, pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens;distributions, enter into sale and leaseback transactions, engage in certain transactions with our affiliates;affiliates, engage in mergers or consolidations, enter into hedging arrangements, and mergeacquire or consolidate with other companies. We were in compliance with all covenantsdispose of the Notes as of September 30, 2017.assets.




Other Long-Term Liabilities


Other long-term liabilities consisted of the following:
  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 andThe table below provides detail on our 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 7 – 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 AROs for the periodsdates indicated:
  Nine Months Ended
  September 30,
  2017 2016
  (In thousands)
ARO liability, January 1: $70,170
 $98,297
Accretion of discount 2,112
 2,147
Liability incurred 1,123
 311
Liability settled (1,350) (874)
Liability sold (1)
 (1,563) (10,758)
Revision of estimates (2)
 4,993

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


June 30,
2022		December 31,
2021
 (In thousands)
Asset retirement obligation (ARO) liability$25,406 $25,688 
Workers’ compensation7,483 7,925 
Contract liability748 1,788 
Separation benefit plans1,658 2,022 
Gas balancing liability1,090 1,090 
36,385 38,513 
Less: current portion5,009 5,574 
Total other long-term liabilities$31,376 $32,939 
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 conditions of a share-based payment award. The amendments are effective for reporting periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements.

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

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

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

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

NOTE 9 –STOCK-BASED COMPENSATION10 – ASSET RETIREMENT OBLIGATIONS


For restricted stock awards and 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 relatedWe are required to unvested awards at September 30, 2017 is approximately $14.2 million, of which $1.7 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is one year.

Our Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as to non-employee directors. A total of 7,000,000 sharesrecord the estimated fair value of the company's common stockliabilities 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 authorizedrecorded 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 issuancepurposes of settling these AROs. All our AROs relate to eligible participants under the amended planplugging costs associated with 2,000,000 shares being the maximum numberour oil and gas wells.
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Table of shares that can be issued as "incentive stock options."Contents


We did not grant any SARs or stock options during either of the three or nine month periods ending September 30, 2017 or 2016. We did not grant any restricted stock awards during either of the three month periods ending September 30, 2017 or 2016. The following table shows certain information about our estimated AROs for the fairperiods indicated:

Six Months Ended June 30,
20222021
(In thousands)
ARO liability, beginning of period$25,688 $23,356 
Accretion of discount974 931 
Liability incurred17 1 
Liability settled(86)(302)
Liability sold(2,671)(721)
Revision of estimates (1)
1,484 (93)
ARO liability, end of period25,406 23,172 
Less: current portion2,707 2,132 
Total long-term ARO$22,699 $21,040 
1.Plugging liability estimates were revised in 2022 and 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.

NOTE 11 – WORKERS' COMPENSATION

We are liable for workers' compensation benefits for traumatic injuries through our self-insured program to provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers' compensation laws also compensate survivors of workers who suffer employment related deaths. Our liability for traumatic injury claims is the estimated present value of restricted stock awards granted to employeescurrent workers' compensation benefits, based on our actuarial estimates. Our actuarial calculations are based on a blend of actuarial projection methods and non-employee directorsnumerous assumptions including claim development patterns, mortality, medical costs and interest rates.

The following table summarizes activity for our workers' compensation liability during the periods indicated:


Six Months Ended June 30,
 20222021
 (In thousands)
Workers' compensation liability, beginning of period$7,925 $10,164 
Claims and valuation adjustments(229)1,748 
Payments(213)(182)
Workers' compensation liability, end of period7,483 11,730 
Less: current portion1,283 1,819 
Long-term workers' compensation liability$6,200 $9,911 
  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%. BasedOur workers' compensation liability above is presented on a probability assessmentgross basis and does not include our expected receivables on our insurance policy. Our receivables for traumatic injury claims under these policies as of the selected performance criteria at SeptemberJune 30, 2017, the participants2022 and December 31, 2021 are estimated to receive 81%$3.8 million and $4.0 million, respectively, and are included in other assets on our unaudited condensed consolidated balance sheets.

20
Table 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.Contents

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. As of September 30, 2017, ourconditions as well as certain requirements stipulated in the Exit credit agreement. Our commodity derivative transactions were comprisedconsisted of the following hedges:types of hedges as of June 30, 2022:


•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. Any changes in the fair valuepurposes and have not designated any of our derivative transactions occurring before maturity (i.e., temporary fluctuations in value)hedges for hedge accounting purposes. We are reported in gain (loss) on derivatives innot required to post any cash collateral with our Unaudited Condensed Consolidated Statementscounterparties and no collateral has been posted as of Operations.June 30, 2022.


At SeptemberThe following non-designated commodity hedges were outstanding as of June 30, 2017, the following derivatives were outstanding:2022:

TermCommodityContracted Volume
Weighted Average��
Fixed Price
Contracted Market
Oct'17Natural gas – swap70,000 MMBtu/day$3.038IF – NYMEX (HH)
Nov’17 – Dec'17Natural gas – swap60,000 MMBtu/day$2.960IF – NYMEX (HH)
Jan’18 – Dec'18Natural gas – swap20,000 MMBtu/day$3.013IF – NYMEX (HH)
Nov’17 – Dec'17Natural gas – basis swap20,000 MMBtu/day$(0.215)IF – NYMEX (HH)
Jan’18 – Mar'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Nov’18 – Dec'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Oct'17Natural gas – collar20,000 MMBtu/day$2.88 - $3.10IF – NYMEX (HH)
Oct'17Natural gas – three-way collar15,000 MMBtu/day$2.50 - $2.00 - $3.32IF – NYMEX (HH)
Nov’17 – Dec'17Natural gas – three-way collar25,000 MMBtu/day$2.90 - $2.30 - $3.59IF – NYMEX (HH)
Jan'18 – Mar'18Natural gas – three-way collar60,000 MMBtu/day$3.29 - $2.63 - $4.07IF – NYMEX (HH)
Apr'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Oct’17 – Dec'17Crude oil – three-way collar3,750 Bbl/day$49.79 - $39.58 - $60.98WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar2,000 Bbl/day$47.50 - $37.50 - $56.08WTI – NYMEX
Jan'18 – Dec'18Crude oil – swap2,000 Bbl/day$50.140WTI – NYMEX

After September 30, 2017, the following derivative was entered into:
Commodity
TermCommodityContracted Volume
Weighted Average 
Fixed Price for Swaps
Contracted Market
Apr'18 – Oct'18Jul'22 - Dec'22Natural gas –- swap10,0005,000 MMBtu/day$2.9902.61IF –- NYMEX (HH)
Apr'18 – Sep'18Jul'22 - Feb'23
Liquids –Natural gas - swap(1)
1,000 Bbl/18,765 MMBtu/day$9.14IF - NYMEX (HH)
Jan'23 - Dec'23Natural gas - swap22,000 MMBtu/day$2.46IF - NYMEX (HH)
Jul'22 - Dec'22Natural gas - collar35,000 MMBtu/day$31.1642.50 - $2.68OPIS – Mont BelvieuIF - NYMEX (HH)
Jul'22 - Dec'22Crude oil - swap2,300 Bbl/day$42.25WTI - NYMEX
Jul'22 - Dec'22Crude oil - swap596 Bbl/day$103.98WTI - NYMEX
Jan'23 - Feb'23Crude oil - swap1,339 Bbl/day$95.40WTI - NYMEX
Jan'23 - Dec'23Crude oil - swap1,300 Bbl/day$43.60WTI - NYMEX
_______________________

(1)    TypeWarrants

Prior to the determination of liquid involved is propane.the initial exercise price, we recognized the fair value of the warrants as a derivative liability on our unaudited condensed consolidated balance sheets with changes in the liability reported as gain (loss) on change in fair value of warrants in our unaudited condensed consolidated statements of operations. On April 7, 2022, the company delivered notice of the initial $63.74 exercise price resulting in the warrants meeting the definition of an equity instrument. Accordingly, we recognized the change in the fair value of the warrant liability in our unaudited condensed consolidated statements of operations and reclassified the $49.1 million warrant liability to capital in excess of par value on the unaudited condensed consolidated balance sheets as of April 7, 2022. The warrants will continue to be reported as capital in excess of par and are no longer subject to future fair value adjustments.

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The following tables present the fair valuesrecognized derivative assets and locations ofliabilities on our unaudited condensed consolidated balance sheets:

Balances as of June 30, 2022
Balance Sheet ClassificationPresented
Gross		Effects of
Netting		Presented
Net
  (In thousands)
Assets:
Current Commodity DerivativesCurrent derivative assets$16,481 $(16,481)$— 
Long-term Commodity DerivativesNon-current derivative assets— — — 
Total derivative assets$16,481 $(16,481)$— 
Liabilities:
Current Commodity DerivativesCurrent derivative liabilities$65,325 $(16,481)$48,844 
Long-term Commodity DerivativesNon-current derivative liabilities17,231 — 17,231 
Total derivative liabilities$82,556 $(16,481)$66,075 

Balances as of December 31, 2021
Balance Sheet ClassificationPresented
Gross		Effects of
Netting		Presented
Net
  (In thousands)
Liabilities:
Current Commodity DerivativesCurrent derivative liabilities$40,876 $— $40,876 
Long-term Commodity DerivativesNon-current derivative liabilities17,855 — 17,855 
Warrant LiabilityWarrant liability19,822 — 19,822 
Total derivative liabilities$78,553 $— $78,553 

The following table shows the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
    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 subjectactivity related 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 in our Unaudited Condensed Consolidated Balance Sheets.

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


Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30:
Three Months Ended June 30,Six Months Ended June 30,
2022202120222021
 (In thousands)
Gain (loss) on derivatives$2,609 $(42,400)$(61,467)$(65,231)
Cash settlements paid on commodity derivatives(32,884)(6,403)(54,123)(9,707)
Gain (loss) on derivatives less cash settlements paid on commodity derivatives$35,493 $(35,997)$(7,344)$(55,524)
Gain (loss) on change in fair value of warrants$7,289 $(3,574)$(29,323)$(3,574)
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 inamounts.

The inputs available determine the valuation technique that we use to measure the 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,assets and (iv)liabilities presented in our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value.

unaudited condensed consolidated financial statements. Fair value is defined asmeasurements are categorized into one of three different levels depending on the amount that would be received fromobservability of the sale of an asset or paid forinputs used in the transfer of 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.measurement. The levels are summarized as follows:


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•Level 1—unadjustedobservable inputs such as quoted prices in active markets for identical assets and liabilities.

•Level 2—significantother observable pricing inputs, other thansuch as quoted prices included within level 1in inactive markets, or other inputs that are either directly or indirectly observable as of the reporting date. Essentially,date, including 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.data or estimates about how market participants would value such assets and liabilities.


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


The following tables set forth our recurring fair value measurements:measurements by level:

  September 30, 2017
  Level 1 Level 2 Level 3 
Effect
of Netting
 Net Amounts Presented
  (In thousands)
Financial assets (liabilities):          
Commodity derivatives:          
Assets $—
 $662
 $1,964
 $(1,562) $1,064
Liabilities —
 (2,002) (478) 1,562
 (918)
Total commodity derivatives —
 (1,340) 1,486
 —
 146
Equity securities 915
 —
 —
 —
 915
  $915
 $(1,340) $1,486
 $—
 $1,061
Balances as of June 30, 2022
 Level 1Level 2Level 3Total
 (In thousands)
Financial liabilities:
Commodity derivative liabilities$— $66,075 $— $66,075 
$— $66,075 $— $66,075 

  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) $—
 $(21,602)
Balances as of December 31, 2021
 Level 1Level 2Level 3Total
 (In thousands)
Financial liabilities:
Commodity derivative liabilities$— $58,731 $— $58,731 
Warrant liability— — 19,822 19,822 
$— $58,731 $19,822 $78,553 


All our counterparties are subject to master netting arrangements. If a legal rightThe carrying values on the unaudited condensed consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because 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.


We used thetheir short-term nature. The following methods and assumptions were used 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).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. We consider these Level 2 measurements within the fair value hierarchy as the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts.


Level 3 Fair Value Measurements

Commodity Derivatives. The fair values ofWe determined that the non-performance risk regarding our natural gas and crude oil collars and three-way collars are estimated using internal discounted cash flow calculationscommodity derivative counterparties was immaterial based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.

The following table is a reconciliation of our level 3 fair value measurements:
  Net Derivatives
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
  (In thousands)
Beginning of period $4,093
 $(4,761) $(7,122) $9,094
Total gains or losses (realized and unrealized):        
Included in earnings (1)
 (2,015) 3,077
 9,102
 (3,257)
Settlements (592) (443) (494) (7,964)
End of period $1,486
 $(2,127) $1,486
 $(2,127)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period $(2,607) $2,634
 $8,608
 $(11,221)
_______________________
(1)Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives.

The following table provides quantitative information about our Level 3 unobservable inputs at September 30, 2017:
Commodity (1)
 Fair Value Valuation Technique Unobservable Input Range
  (In thousands)      
Oil three-way collars $(9) Discounted cash flow Forward commodity price curve ($3.65) - $5.02
Natural gas collar $25
 Discounted cash flow Forward commodity price curve ($0.11) - $0.06
Natural gas three-way collars $1,470
 Discounted cash flow Forward commodity price curve ($0.34) - $0.54
 _______________________
(1)The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Our valuation at SeptemberJune 30, 2017 reflected that2022.
Warrant Liability. We use the risk of non-performance by our counterparties was immaterial.

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 dataBlack-Scholes option pricing model 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, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature.

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

The carrying amounts of long-term debt associated with the Notes, net of unamortized discount and debt issuance costs, reported in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 were $641.7 million and $640.1 million, respectively. We estimatemeasure the fair value of the Notes using quoted marked prices at September 30, 2017warrants. Key inputs for the Black-Scholes model include the stock price, exercise price, expected term, risk-free rate, volatility, and December 31, 2016 was $654.6 milliondividend yield. We consider this a Level 3 measurement within the fair value hierarchy as estimated volatility is generally unobservable and $649.9 million, respectively. requires management's estimation.

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The Notes would be classified asfollowing table summarizes the activity of our recurring Level 2.3 fair value measurements during the periods presented:


Three Months Ended June 30,Six Months Ended June 30,
2022202120222021
 (In thousands)
Beginning of period$56,434 $885 $19,822 $885 
(Gain) loss on change in warrant liability(7,289)3,574 29,323 3,574 
Reclassification of warrant liability to capital in excess of par value(49,145)— (49,145)— 
End of period$— $4,459 $— $4,459 

Nonrecurring Fair Value of Non-Financial InstrumentsMeasurements


ARO.The initial measurement of AROsARO 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 reconciliationsummary of the Company’s AROscompany’s ARO activity is presented in Note 710 – Asset Retirement Obligations.


Stock-Based Compensation. We use the Black-Scholes option pricing model to estimate the fair value of stock option grants while the value of our restricted stock grants is based on the grant date closing stock price. Key assumptions for the Black-Scholes models include the stock price, exercise price, expected term, risk-free rate, volatility, and dividend yield. We consider this a Level 3 measurement within the fair value hierarchy as estimated volatility is generally unobservable and requires management's estimation.

See Note 15 - Superior Investment for discussion on the estimated fair value of our retained equity method investment in Superior as of March 1, 2022.

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NOTE 14 – LEASES

Operating Leases. We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of office space, land, vehicles, and equipment used in both our operations and administrative functions.

The following table sets forth the maturities, weighted average remaining lease term, and weighted average discount rate of our operating lease liabilities as of June 30, 2022:

Amount
(In thousands)
Ending June 30,
2022$2,017 
20231,996 
20242,024 
20252,065 
2026437 
2027 and beyond— 
Total future payments8,539 
Less: Interest1,115 
Present value of future minimum operating lease payments7,424 
Less: Current portion1,571 
Total long-term operating lease payments$5,853 
Weighted average remaining lease term (years)4.2
Weighted average discount rate (1)
6.65 %
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.

Finance Leases. During 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 4.0% and the underlying assets were included in gas gathering and processing equipment. Superior purchased the leased assets for $3.0 million in May 2021.
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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 sheetsJune 30,
2022		December 31,
2021
(In thousands)
Assets
Operating lease right of use assetsRight of use assets$7,362 $12,445 
Total right of use assets$7,362 $12,445 
Liabilities
Current liabilities:
Operating lease liabilitiesCurrent operating lease liabilities$1,571 $3,791 
Non-current liabilities:
Operating lease liabilitiesOperating lease liabilities5,853 8,677 
Total lease liabilities$7,424 $12,468 

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

Three Months Ended June 30,Six Months Ended June 30,
2022202120222021
(In thousands)
Components of total lease cost:
Amortization of finance leased assets$— $181 $— $1,248 
Interest on finance lease liabilities— 4 — 33 
Operating lease cost923 984 2,231 2,011 
Short-term lease cost (1)
3,418 3,179 6,954 5,771 
Variable lease cost— — 0— 
Total lease cost$4,341 $4,348 $9,185 $9,063 
1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $0.7 million and $0.1 million during the three months ended June 30, 2022 and 2021, respectively, and $1.2 million and $0.2 million during the six months ended June 30, 2022 and 2021, respectively.

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

Six Months Ended June 30,
20222021
(In thousands)
Cash payments made on operating leases$2,190 $2,063 
Cash payments made on finance leases$— $3,216 
Lease liabilities recognized in exchange for new operating lease right of use assets$909 $167 

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NOTE 15 – SUPERIOR INVESTMENT

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

Distributions. The Agreement specifies how future distributions are to be allocated among Unit Corporation and SP Investor (the Members). Distributions from Available Cash (as defined in the Agreement) were generally split evenly between the Members prior to December 31, 2021, when the three-year period for Unit's commitment to spend $150.0 million (Drilling Commitment Amount) to drill wells in the Granite Wash/Buffalo Wallow area ended. The total amount spent by Unit towards the Drilling Commitment Amount was $24.6 million. Accordingly, SP Investor will receive 100% of Available Cash distributions related to periods subsequent to December 31, 2021 until the $72.7 million Drilling Commitment Adjustment Amount (as defined in the Agreement) is satisfied.

Superior paid cash distributions of $9.5 million to each of the Members in January 2022 representing Available Cash generated during the three months ended December 31, 2021, and paid distributions to SP Investor of $10.5 million in April 2022 representing Available Cash generated during the three months ended March 31, 2022 and $13.9 million in July 2022 representing Available Cash generated during the three months ended June 30, 2022. The distributions paid to SP Investor in July 2022 reduced the remaining Drilling Commitment Adjustment Amount to $48.2 million.

Distributions paid by Superior during the three and six months ended June 30, 2021 totaled $24.7 million. Unit and SP Investor each received 50% of these distributions.

Sale Event. After April 1, 2023, either Member may initiate a sale process of Superior to a third-party or a liquidation of Superior's assets (Sale Event). In a Sale Event, the Agreement generally requires cumulative distributions to SP Investor in excess of its original $300.0 million investment sufficient to provide SP Investor a 7% internal rate of return on its capital contributions to Superior before any liquidation distribution is made to Unit. As of June 30, 2022, liquidation distributions paid first to SP Investor of $353.7 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 $353.7 million of the remaining liquidation distributions to satisfy Unit's 7% Liquidation IRR Hurdle with any remaining liquidation distributions paid as outlined within the Agreement.

Consolidation. From April 3, 2018 to March 1, 2022, we treated Superior as a variable interest entity (VIE) because the equity holders as a group (Unit Corporation and SP Investor) lacked the power to control without the Operator. The Agreement and MSA gave us the power to direct the activities that most significantly affect Superior's operating performance through common control of the Operator. Accordingly, Unit was considered the primary beneficiary and consolidated the financial position, operating results, and cash flows of Superior.

Effective March 1, 2022, the employees of the Operator were transferred to Superior and the MSA was amended and restated to remove the operating services the Operator was providing to Superior. There was no change to the monthly service fee for shared services. The power to direct the activities that most significantly affect Superior's operating performance is now shared by the equity holders (Unit Corporation and SP Investor) rather than held by the Operator. Superior no longer qualifies as a VIE subsequent to these amendments and we no longer consolidate the financial position, operating results, and cash flows of Superior as of, and subsequent to, March 1, 2022.

We subsequently account for our investment in Superior as an equity method investment using the hypothetical liquidation book value (HLBV) method, 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 period. We recognized no equity earnings from our investment in Superior during the three and six months ended June 30, 2022.

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Estimated Fair Value of Equity Method Investment in Superior. As of the Effective Date, in conjunction with fresh start accounting under ASC Topic 852, Reorganizations, the estimated fair value of the net equity attributable to Unit's ownership interest in Superior was $14.8 million. Since then, Unit has received cumulative distributions from Superior of $32.6 million, which were recognized as net income attributable to Unit under the HLBV method. As of March 1, 2022, upon deconsolidation of Superior, the fair value of our retained equity method investment in Superior was estimated at $1.7 million. To estimate this fair value, we simulated paths for Superior's total equity value through the potential sales process initiation date using a Geometric Brownian Motion. The expected value (i.e., average of all simulations) of each security class was then discounted to present value using the relevant risk-free rate. The simulations reflect forecasted future cash distributions as impacted by the Drilling Commitment Adjustment Amount described above, as well as the future liquidation preference of each investor in a potential Sale Event also as described above. We consider this a Level 3 measurement within the fair value hierarchy as the discounted simulation models require the use of significant unobservable inputs.

We recognized a $13.1 million loss on deconsolidation during the three months ended March 31, 2022 as the difference between the $1.7 million estimated fair value of our retained equity method investment in Superior as of March 1, 2022 and Superior's net equity attributable to Unit's ownership interest prior to deconsolidation.
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Superior Balance Sheet Disclosure. The amounts below reflect the Superior balance sheet accounts, without elimination of intercompany receivables from and payables to Unit, consolidated in our unaudited condensed consolidated balance sheets as of December 31, 2021 which was the last reporting date as of which we consolidated the financial position of Superior:

December 31,
2021
(In thousands)
Current assets:
Cash and cash equivalents$17,246 
Accounts receivable42,628 
Prepaid expenses and other1,263 
Total current assets61,137 
Property and equipment:
Gas gathering and processing equipment274,748 
Transportation equipment2,801 
277,549 
Less accumulated depreciation, depletion, amortization, and impairment53,792 
Net property and equipment223,757 
Right of use asset3,485 
Other assets2,226 
Total assets$290,605 
Current liabilities:
Accounts payable$34,010 
Accrued liabilities5,292 
Current operating lease liability1,450 
Current portion of other long-term liabilities1,548 
Total current liabilities42,300 
Long-term debt19,200 
Operating lease liability2,036 
Total liabilities$63,536 

Affiliate Activity. UPC's oil and natural gas revenues with Superior totaled $19.5 million and $9.3 million during the three months ended June 30, 2022 and 2021, respectively, and $35.8 million and $17.9 million during the six months ended June 30, 2022 and 2021, respectively. UPC's gas gathering and processing expenses with Superior totaled $0.8 million and $0.9 million during the three months ended June 30, 2022 and 2021, respectively, and $1.6 million and $1.7 million during the six months ended June 30, 2022 and 2021, respectively. Portions of this activity was eliminated for the periods during which Superior was consolidated by Unit.

NOTE 1216 – COMMITMENTS AND CONTINGENCIES


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-term commitments to stack excess drilling rig equipment 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 nine months of 2017 and 2016, respectively.Environmental

In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the four successive twelve month periods beginning October 1, 2017 (and through the end of 2021) are $6.2 million, $6.2 million, $6.2 million, and $5.3 million. Total maintenance and interest remaining related to these leases are $6.3 million and $1.3 million, respectively at September 30, 2017. Annual payments, net of maintenance and interest, average $4.1 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value.

The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal. 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.


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.


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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.


Litigation

The company is subject to litigation and claims arising in the ordinary course of business which may include environmental, health and safety matters, commercial disputes with customers, 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.

In February 2021, UPC finalized a settlement agreement for $2.1 million related to a well drilled in Beaver County, Oklahoma during 2013. 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 finalized the settlement agreement while the case was pending review in the Oklahoma Court of Civil Appeals.

NOTE 17 – INCOME TAXES

For the next twelvethree and six months we have committedended June 30, 2022 and 2021, respectively, the company’s effective income tax rate was 0.0% which differs from the statutory rate of 21.0% primarily due to purchase approximately $3.9 million of new drilling rig components.


NOTE 13 – EQUITY

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 offerchanges in, and sell, from time to time, through the sales agent sharescontinued need of, our common stock, par value $.20 per share (the Shares), up to an aggregate offering price of $100.0 million. full valuation allowance, changes in the warrant liability valuation, and state income taxes.

We intend to useconcluded that it is more likely than not that the net proceeds from these salesdeferred tax asset will not be realized and has recorded a full valuation allowance, reducing the net deferred tax asset to fund (or offset costs of) acquisitions,zero. We maintained this conclusion as of June 30, 2022 and December 31, 2021. We will continue to evaluate whether the valuation allowance is needed in future capital expenditures, repay amounts outstanding under our revolving credit facility,reporting periods and general corporate purposes.
Underit will remain until we can conclude that the Agreement, the sales agent may sell the Shares by methods deemednet deferred tax assets are more likely than not 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 Sharesrealized. Future events or new evidence which may lead us 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 and conditions of the Agreement, the sales agentconclude that it is more likely than not its net deferred tax assets will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions that we may impose).
Webe realized include, but are not obligatedlimited to, make any sales ofcumulative historical pre-tax earnings, sustained significant improvements in commodity prices, a sustained significant increase in rig utilization and/or rates, 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 Shares undercompany from utilizing the Agreement. The offering of Shares undertax attributes if the Agreementcompany recognizes taxable income. As long as we continue to conclude that the valuation allowance against the net deferred tax assets is necessary, the company will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreementnot have significant deferred income tax expense 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.benefit.

As of September 30, 2017, we sold 787,547 sharesDecember 31, 2021, the company had an expected federal net operating loss carryforward of $385.5 million after consideration of the tax attribute reductions of IRC Section 108, finalization of the company’s 2020 federal income tax return, and pending finalization of the company's 2021 federal income tax return of which $190.5 million is subject to expiration between 2036 and 2037. As of December 31, 2021, our common stock resultingtax basis in net proceeds ofUPC's properties was approximately $18.6$475.0 million.


Accumulated Other Comprehensive Income

NOTE 18 – TRANSACTIONS WITH RELATED PARTIES
Components
One current director, Robert Anderson, also serves as an executive with GBK Corporation, a holding company with numerous energy and industry subsidiaries and affiliates, including Kaiser Francis Oil Company. The company in the ordinary course of accumulated other comprehensive income were as followsbusiness, made payments for working interests, joint interest billings, and product purchases to, and received payments for working interests, drilling services, and joint interest billings from, Kaiser Francis Oil Company. Payments made to Kaiser Francis Oil Company totaled $0.7 million and $0.6 million while payments received totaled $3.6 million and $0.3 million during the three months ended September 30:June 30, 2022 and 2021, respectively, and payments made to Kaiser Francis Oil Company totaled $4.2 million and $1.0 million while payments received totaled $7.5 million and $1.3 million during the six months ended June 30, 2022 and 2021, respectively.
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  2017 2016
  (In thousands)
Unrealized appreciation on securities, before tax $53
 $—
Tax expense (20) —
Unrealized appreciation on securities, net of tax $33
 $—

ChangesOne former director, G. Bailey Peyton IV, also serves as Manager and 99.5% owner of Peyton Royalties, LP, a family-controlled limited partnership that owns royalty rights in accumulated other comprehensive income by component, netwells in several states. The company in the ordinary course of tax, forbusiness, paid royalties, or lease bonuses, primarily due to its status as successor in interest to prior transactions and as operator of the wells involved and, sometimes, as lessee, regarding certain wells in which Mr. Peyton, members of Mr. Peyton's family, and Peyton Royalties, LP have an interest. Such payments totaled $0.1 million and $0.1 million during the three months ended SeptemberJune 30, are as follows:
  Net Gains on Equity Securities
  2017 2016
  (In thousands)
Balance at July 1: $20
 $—
Unrealized appreciation before reclassifications 33
 —
Amounts reclassified from accumulated other comprehensive income —
 —
Net current-period other comprehensive income 33
 —
Balance at September 30: $53
 $—


Components of accumulated other comprehensive income were as follows for2022 and 2021, respectively, and $0.3 million and $0.2 million during the ninesix months ended September 30:June 30, 2022 and 2021, respectively.

  2017 2016
  (In thousands)
Unrealized appreciation on securities, before tax $85
 $—
Tax expense (32) —
Unrealized appreciation on securities, net of tax $53
 $—

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

NOTE 1419 – 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

Our - the oil and natural gas segment is engaged in the acquisition, development, and production of oil, NGLs, and natural gas properties. The
•Contract drilling - the contract drilling segment is engaged in the land contract drilling of oil and natural gas wells andwells.
•Mid-Stream - the mid-stream segment is engaged in the buying, selling, gathering, processing,buys, sells, gathers, processes, and treating oftreats natural gas and NGLs.NGLs for third parties and for our own account. We presently own 50% of this subsidiary, and subsequent to the deconsolidation of Superior as of March 1, 2022 (as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment), we will continue to include our equity method investment in Superior and related earnings in our mid-stream segment.


We evaluate each consolidated 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 or other operations outside the United States.



The following tables provide certain information about the operations of each of our segments:
  Three Months Ended September 30, 2017
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues:            
Oil and natural gas $85,470
 $—
 $—
 $—
 $—
 $85,470
Contract drilling —
 55,588
 —
 —
 (3,969) 51,619
Gas gathering and processing —
 —
 69,057
 —
 (17,658) 51,399
Total revenues 85,470
 55,588
 69,057
 —
 (21,627) 188,488
Expenses:            
Operating costs:            
Oil and natural gas 35,082
 —
 —
 —
 (1,171) 33,911
Contract drilling —
 38,115
 —
 —
 (3,368) 34,747
Gas gathering and processing —
 —
 54,602
 —
 (16,486) 38,116
Total operating costs 35,082
 38,115
 54,602
 —
 (21,025) 106,774
Depreciation, depletion, and amortization 26,460
 15,280
 10,880
 1,913
 —
 54,533
Total expenses 61,542
 53,395
 65,482
 1,913
 (21,025) 161,307
Total operating income (loss) (1)
 23,928
 2,193
 3,575
 (1,913) (602)  
General and administrative expense —
 —
 —
 (9,235) —
 (9,235)
Gain (loss) on disposition of assets (1) 68
 14
 —
 —
 81
Loss on derivatives —
 —
 —
 (2,614) —
 (2,614)
Interest expense, net —
 —
 —
 (9,944) —
 (9,944)
Other —
 —
 —
 5
 —
 5
Income (loss) before income taxes $23,927
 $2,261
 $3,589
 $(23,701) $(602) $5,474

_______________________
Three Months Ended June 30, 2022
 Oil and Natural GasContract DrillingMid-StreamCorporate and OtherEliminationsTotal Consolidated
 (In thousands)
Revenues: (1)
Oil and natural gas$100,896 $— $— $— $16 $100,912 
Contract drilling— 33,642 — — — 33,642 
Total revenues100,896 33,642 — — 16 134,554 
Expenses:
Operating costs:
Oil and natural gas27,603 — — — 16 27,619 
Contract drilling— 25,763 — — — 25,763 
Total operating costs27,603 25,763 — — 16 53,382 
Depreciation, depletion, and amortization4,027 1,558 — 76 — 5,661 
Total expenses31,630 27,321 — 76 16 59,043 
General and administrative— — — 7,421 — 7,421 
Gain on disposition of assets(25)(2,041)— — — (2,066)
Income (loss) from operations69,291 8,362 — (7,497)— 70,156 
Gain on derivatives— — — 2,609 — 2,609 
Gain on change in fair value of warrants— — — 7,289 — 7,289 
Reorganization items, net— — — (39)— (39)
Interest, net— — — (97)— (97)
Other13 9 — 153 — 175 
Income before income taxes$69,304 $8,371 $— $2,418 $— $80,093 
(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.

1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.
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  Three Months Ended September 30, 2016
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues:            
Oil and natural gas $78,854
 $—
 $—
 $—
 $—
 $78,854
Contract drilling —
 25,819
 —
 —
 —
 25,819
Gas gathering and processing —
 —
 63,090
 —
 (14,355) 48,735
Total revenues 78,854
 25,819
 63,090
 —
 (14,355) 153,408
Expenses:            
Operating costs:            
Oil and natural gas 27,710
 —
 —
 —
 (1,696) 26,014
Contract drilling —
 19,137
 —
 —
 —
 19,137
Gas gathering and processing —
 —
 48,397
 —
 (12,659) 35,738
Total operating costs 27,710
 19,137
 48,397
 —
 (14,355) 80,889
Depreciation, depletion, and amortization 27,135
 11,318
 11,436
 80
 —
 49,969
Impairments 49,443
 —
 —
 —
 —
 49,443
Total expenses 104,288
 30,455
 59,833
 80
 (14,355) 180,301
Total operating income (loss)(1)
 (25,434) (4,636) 3,257
 (80) —
  
General and administrative expense —
 —
 —
 (8,852) —
 (8,852)
Gain on disposition of assets —
 151
 —
 3
 —
 154
Gain on derivatives —
 —
 —
 6,969
 —
 6,969
Interest expense, net —
 —
 —
 (10,002) —
 (10,002)
Other —
 —
 —
 3
 —
 3
Income (loss) before income taxes $(25,434) $(4,485) $3,257
 $(11,959) $—
 $(38,621)

_______________________
(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.





Three Months Ended June 30, 2021
 Oil and Natural GasContract DrillingMid-StreamCorporate and OtherEliminationsTotal Consolidated
 (In thousands)
Revenues: (1)
Oil and natural gas$59,776 $— $— $— $(17,806)$41,970 
Contract drilling— 18,061 — — — 18,061 
Gas gathering and processing— — 66,323 — 7,703 74,026 
Total revenues59,776 18,061 66,323 — (10,103)134,057 
Expenses:
Operating costs:
Oil and natural gas16,350 — — — (863)15,487 
Contract drilling— 14,080 — — — 14,080 
Gas gathering and processing— — 55,176 — (10,120)45,056 
Total operating costs16,350 14,080 55,176 — (10,983)74,623 
Depreciation, depletion, and amortization6,476 1,570 8,064 254 — 16,364 
Total expenses22,826 15,650 63,240 254 (10,983)90,987 
General and administrative— — — 4,871 880 5,751 
Gain on disposition of assets(67)(1,618)— (25)— (1,710)
Income (loss) from operations37,017 4,029 3,083 (5,100)— 39,029 
Loss on derivatives— — — (42,400)— (42,400)
Loss on change in fair value of warrants— — — (3,574)— (3,574)
Reorganization items, net— — — (1,852)— (1,852)
Interest, net— — 641 (1,128)— (487)
Other34 11 (850)(26)— (831)
Income (loss) before income taxes$37,051 $4,040 $2,874 $(54,080)$— $(10,115)
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

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Six Months Ended June 30, 2022
 Nine Months Ended September 30, 2017Oil and Natural GasContract Drilling
Mid-Stream (2)
Corporate and Other
Eliminations (2)
Total Consolidated
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated(In thousands)
 (In thousands)
Revenues:            
Revenues: (1)
Revenues: (1)
Oil and natural gas $256,241
 $—
 $—
 $—
 $—
 $256,241
Oil and natural gas$188,478 $— $— $— $(10,756)$177,722 
Contract drilling —
 137,617
 —
 —
 (9,558) 128,059
Contract drilling— 62,524 — — 062,524 
Gas gathering and processing —
 —
 198,632
 —
 (48,139) 150,493
Gas gathering and processing— 083,198 — (525)82,673 
Total revenues 256,241
 137,617
 198,632
 —
 (57,697) 534,793
Total revenues188,478 62,524 83,198 — (11,281)322,919 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 99,349
 —
 —
 —
 (3,476) 95,873
Oil and natural gas51,603 — — — (509)51,094 
Contract drilling —
 99,794
 —
 —
 (8,581) 91,213
Contract drilling— 52,000 — — — 52,000 
Gas gathering and processing —
 —
 156,525
 —
 (44,663) 111,862
Gas gathering and processing— — 73,771 — (11,383)62,388 
Total operating costs 99,349
 99,794
 156,525
 —
 (56,720) 298,948
Total operating costs51,603 52,000 73,771 — (11,892)165,482 
Depreciation, depletion, and amortization 71,544
 41,896
 32,547
 5,558
 —
 151,545
Depreciation, depletion, and amortization8,075 3,092 5,614 150 — 16,931 
ImpairmentImpairment— — — — — — 
Total expenses 170,893
 141,690
 189,072
 5,558
 (56,720) 450,493
Total expenses59,678 55,092 79,385 150 (11,892)182,413 
Total operating income (loss)(1)
 85,348
 (4,073) 9,560
 (5,558) (977)  
General and administrative expense —
 —
 —
 (26,902) —
 (26,902)
Gain on disposition of assets 176
 106
 58
 813
 —
 1,153
Gain on derivatives —
 —
 —
 21,019
 —
 21,019
Interest expense, net —
 —
 —
 (28,807) —
 (28,807)
General and administrativeGeneral and administrative— — — 13,336 611 13,947 
(Gain) loss on disposition of assets(Gain) loss on disposition of assets(79)(4,165)— 3 — (4,241)
Income (loss) from operationsIncome (loss) from operations128,879 11,597 3,813 (13,489)— 130,800 
Loss on derivativesLoss on derivatives— — — (61,467)— (61,467)
Loss on change in fair value of warrantsLoss on change in fair value of warrants— — — (29,323)— (29,323)
Loss on deconsolidation of SuperiorLoss on deconsolidation of Superior— — — (13,141)— (13,141)
Reorganization items, netReorganization items, net— — — (42)— (42)
Interest, netInterest, net— — (179)(192)— (371)
Other —
 —
 —
 14
 —
 14
Other721 28 17 166 — 932 
Income (loss) before income taxes $85,524
 $(3,967) $9,618
 $(39,421) $(977) $50,777
Income (loss) before income taxes$129,600 $11,625 $3,651 $(117,488)$— $27,388 
_______________________
(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.

2.Includes Superior activity for the two months prior to the March 1, 2022 deconsolidation, as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment.


33
Table of Contents
Six Months Ended June 30, 2021
 Nine Months Ended September 30, 2016Oil and Natural GasContract DrillingMid-StreamCorporate and OtherEliminationsTotal Consolidated
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated(In thousands)
 (In thousands)
Revenues:            
Revenues: (1)
Revenues: (1)
Oil and natural gas $206,318
 $—
 $—
 $—
 $—
 $206,318
Oil and natural gas$114,801 $— $— $— $(17,807)$96,994 
Contract drilling —
 88,786
 —
 —
 —
 88,786
Contract drilling— 33,735 — — — 33,735 
Gas gathering and processing —
 —
 168,668
 —
 (35,875) 132,793
Gas gathering and processing— — 125,932 — (1,707)124,225 
Total revenues 206,318
 88,786
 168,668
 —
 (35,875) 427,897
Total revenues114,801 33,735 125,932 — (19,514)254,954 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 98,070
 —
 —
 —
 (5,379) 92,691
Oil and natural gas36,343 — — — (1,707)34,636 
Contract drilling —
 66,489
 —
 —
 —
 66,489
Contract drilling— 25,951 — — — 25,951 
Gas gathering and processing —
 —
 129,681
 —
 (30,496) 99,185
Gas gathering and processing— — 104,286 — (19,567)84,719 
Total operating costs 98,070
 66,489
 129,681
 —
 (35,875) 258,365
Total operating costs36,343 25,951 104,286 — (21,274)145,306 
Depreciation, depletion, and amortization 89,378
 34,431
 34,410
 218
 —
 158,437
Depreciation, depletion, and amortization14,131 3,145 16,096 503 — 33,875 
Impairments 161,563
 —
 —
 —
 —
 161,563
ImpairmentImpairment— — — — — — 
Total expenses 349,011
 100,920
 164,091
 218
 (35,875) 578,365
Total expenses50,474 29,096 120,382 503 (21,274)179,181 
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 assets— — — — — — 
General and administrativeGeneral and administrative— — — 11,160 1,760 12,920 
(Gain) loss on disposition of assets(Gain) loss on disposition of assets(87)(2,146)75 (24)— (2,182)
Income (loss) from operationsIncome (loss) from operations64,414 6,785 5,475 (11,639)— 65,035 
Loss on derivatives —
 —
 —
 (4,774) —
 (4,774)Loss on derivatives— — — (65,231)— (65,231)
Interest expense, net —
 —
 —
 (30,225) —
 (30,225)
Loss on change in fair value of warrantsLoss on change in fair value of warrants— — — (3,574)— (3,574)
Reorganization items, netReorganization items, net— — — (2,988)— (2,988)
Interest, netInterest, net— — (416)(2,777)— (3,193)
Other —
 —
 —
 (11) —
 (11)Other90 16 (839)(22)— (755)
Income (loss) before income taxes $(143,017) $(10,667) $4,275
 $(61,057) $—
 $(210,466)Income (loss) before income taxes$64,504 $6,801 $4,220 $(86,231)$— $(10,706)
_______________________
(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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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 2021 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, 2022.


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,produces, develops, acquires, and producesacquires 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 hold a 50% investment in Superior.

Oil and Natural Gas

In our oil and natural gas segment.
segment, we are optimizing production and converting non-producing reserves to producing with selective drilling activities. We also anticipate continuing to hedge a portion of our future production depending on future market pricing among other factors.

Contract Drilling
Business Outlook

In our contract drilling segment, we are focused on maintaining utilization of our BOSS and SCR drilling rigs in a safe and efficient manner. All 14 of our BOSS drilling rigs are currently operating in addition to three of our SCR drilling rigs. We continue to evaluate opportunities to place one or more of our four non-operating SCR drilling rigs back in service.
As discussed
Mid-Stream

In our mid-stream segment, Superior is focused on continuing to generate predictable free cash flows with limited exposure to commodity prices in addition to seeking business development opportunities in its core areas utilizing the Superior credit agreement (which Unit is not a party to and does not guarantee) or other partsfinancing sources that are available to it. We hold a 50% investment in Superior, and subsequent to the deconsolidation of thisSuperior as of March 1, 2022, we report our ownership interest as an equity method investment. The following discussion of financial condition and results of operations pertaining to our mid-stream segment as of the second quarter of 2022 relates to the two months of consolidated results prior to deconsolidation as of March 1, 2022.

Recent Developments

Commodity Price Environment and COVID-19 Pandemic

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.industry, including political and economic uncertainty as well as geopolitical activity.


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-20220630_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-20220630_g3.jpg
1.NGL prices reflect the monthly average Mont Belvieu price.



36
Table of 2016 and the second quarterContents
Stock Repurchases

In June 2021, we repurchased an aggregate of 2017, respectively. Our drilling rig segment's rig utilization increased from 16 drilling rigs working as of June 30, 2016, to 33 drilling rigs working as of September 30, 2017. The extent and duration of this improvement remains uncertain.


The reduction in oil, NGLs, and natural gas prices had a number of 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 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 quarter of 2017), our forward looking expectation is that we will not recognize an impairment in the fourth quarter of 2017. But commodity prices (and other factors) remain volatile and they could negatively impact the 12-month average price resulting in the potential for an impairment in the future.
We reduced the number of gross wells our oil and natural gas segment drilled in 2016 by approximately 64% from the number drilled in 2015 due to our reduced cash flow. For 2017, we plan to increase the number of gross wells drilled to 60 - 65 wells (depending on future commodity prices).
The decline in drilling by our customers reduced the average utilization of our drilling rig fleet. At December 31, 2015, we had 26 drilling rigs operating. In 2016, utilization continued downward bottoming out in May 2016 at 13 operating drilling rigs. After May commodity prices began improving for the remainder of the year and we exited 2016 with 21 active rigs. As of September 30, 2017, we had 33 drilling rigs operating (an improvement of 57% over the end of the year). Operators have been increasing drilling, but the extent of further increases remain uncertain. During the second quarter of 2017, we completed the construction of our tenth BOSS drilling rig and all of our BOSS drilling rigs are under contract.
Due to low ethane price, we continue to operate some of our mid-stream processing facilities in ethane rejection mode which reduces the amount of liquids sold.  As long as ethane price relative to natural gas price remains depressed, we expect to continue operating in ethane rejection mode at some of our processing facilities.
Also, as noted elsewhere, beginning on April 4, 2017, we began an at-the-market offering for the sale of600,000 shares of our 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 our 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. The offering allows usBoard subsequently authorized increases to sell shares, from time to time,the authorized repurchases up to $50.0 million in October 2021 and then up to $100.0 million in June 2022. 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 June 30, 2022, we had repurchased a total of 1,519,392 shares under the repurchase program at an average share price of $36.00 for an aggregate purchase price of $100 million in gross proceeds. As of September$54.7 million. Subsequent to June 30, 2017,2022, we sold 787,547have repurchased an additional 75,000 shares for $18.6 million, net of offering costs of $0.4 million. Approximately $81.0 million remain available for sale under the program. Net proceeds fromrepurchase program for an aggregate purchase price of $3.8 million.

During the offering will be usedyear ended December 31, 2021, we also repurchased 78,000 shares in a privately negotiated transaction at a share price of $19.07 which were not part of the repurchase program.

The cumulative number of shares repurchased as of June 30, 2022 totaled 2,197,392.

Superior MSA and LLCA amendments

Effective March 1, 2022, the employees of the Operator were transferred to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility,Superior and general corporate purposes.

On April 3, 2017, we closed an acquisitionthe MSA was amended and restated to remove the operating services the Operator was providing to Superior. There was no change to the monthly service fee for shared services. We no longer consolidate the financial position, operating results, and cash flows of certain oilSuperior as of, 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 adjustedsubsequent to, March 1, 2022. We recognized a $13.1 million loss on deconsolidation during the six months ended June 30, 2022 as the difference between the $1.7 million estimated fair value of consideration given was $54.3 million. The effective dateour retained equity method investment in Superior as of this acquisition was JanuaryMarch 1, 2017.

Executive Summary

Oil2022 and Natural Gas

Third quarter2017 production fromSuperior's net equity attributable to Unit's ownership interest prior to deconsolidation. We subsequently account for our oil and natural gas segment was 4,057,000 barrels of oil equivalent (Boe),investment in Superior as an increase of 5% overequity method investment using the second quarter of 2017 andhypothetical liquidation book value (HLBV) method which is a decrease of 3% frombalance sheet approach that calculates the third quarter of 2016, respectively. The increase over the second quarter of 2017 was from acquired wells and new wells drilledchange in the first nine months of 2017. The decrease from the third quarter of 2016 was primarily duehypothetical amount Unit and SP Investor would be entitled 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 Harveyreceive if Superior were principally due to NGL bottlenecks from fractionation plant partial shut-downs and operational delays on new wells and recompletions. After the end of the quarter, the third-party processing plant for the majority of Unit’s natural gas production in the Gulf Coast area went down due to an equipment failure. The plant was down seven days before operations resumed. Cumulatively, hurricane Harvey, the Texas Panhandle ice storm in the first quarter, and third party plant downtimes will reduce production for the year by approximately 460 MBoe. 

Third quarter 2017 oil and natural gas revenues increased 3% over the second quarter of 2017 and increased 8% over the third quarter of 2016. The increase over the second quarter of 2017 was due primarily to higher oil and NGL prices and higher

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

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

Operating cost per Boe produced for the third quarter of 2017 decreased 2% from the second quarter of 2017 and increased 35% over the third quarter of 2016. The decrease from the second quarter of 2017 was primarily due to higher production volumes partially offset by higher lease operating expenses and higher production taxes. The increase over the third quarter of 2016 was primarily due to lower production volumes, increased lease operating expenses, and higher production taxes partially offset by lower salt water disposal expense.

At September 30, 2017, we had these derivatives outstanding:
TermCommodityContracted Volume
Weighted Average 
Fixed Price
Contracted Market
Oct'17Natural gas – swap70,000 MMBtu/day$3.038IF – NYMEX (HH)
Nov’17 – Dec'17Natural gas – swap60,000 MMBtu/day$2.960IF – NYMEX (HH)
Jan’18 – Dec'18Natural gas – swap20,000 MMBtu/day$3.013IF – NYMEX (HH)
Nov’17 – Dec'17Natural gas – basis swap20,000 MMBtu/day$(0.215)IF – NYMEX (HH)
Jan’18 – Mar'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Nov’18 – Dec'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Oct'17Natural gas – collar20,000 MMBtu/day$2.88 - $3.10IF – NYMEX (HH)
Oct'17Natural gas – three-way collar15,000 MMBtu/day$2.50 - $2.00 - $3.32IF – NYMEX (HH)
Nov’17 – Dec'17Natural gas – three-way collar25,000 MMBtu/day$2.90 - $2.30 - $3.59IF – NYMEX (HH)
Jan'18 – Mar'18Natural gas – three-way collar60,000 MMBtu/day$3.29 - $2.63 - $4.07IF – NYMEX (HH)
Apr'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Oct’17 – Dec'17Crude oil – three-way collar3,750 Bbl/day$49.79 - $39.58 - $60.98WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar2,000 Bbl/day$47.50 - $37.50 - $56.08WTI – NYMEX
Jan'18 – Dec'18Crude oil – swap2,000 Bbl/day$50.140WTI – NYMEX

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

For the nine months ended September 30, 2017, we completed drilling 43 gross wells (15.10 net wells). For all of 2017, we plan to participate in the drilling of approximately 60 to 65 gross wells.Excluding acquisitions and ARO liability, our estimated 2017 capital expenditures for this segment are approximately $216.0 million. Our current 2017 production guidance is approximately 16.0 MMBoe, a decrease of 7% from 2016, although actual results continue to be subject to many factors.

Contract Drilling

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

Revenue for the third quarter of 2017 increased 31% and 100% over the second quarter of 2017 and the third quarter of 2016, respectively. The increase over the second quarter of 2017 was primarily due to an increase in drilling rigs operating and

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

Dayrates for the third quarter of 2017 averaged $16,454, a 3% increase over the second quarter of 2017 and a 6% decrease from the third quarter of 2016. The increase over the second quarter of 2017 was primarily due to a labor increase that was passed through to contracted rigs. The decrease from the third quarter of 2016 was primarily due to downward pressure on dayrates due to lower demand as higher rate contracts were expiring.

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

Almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The improved commodity 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 outliquidated at 13 drilling rigs operating during the second quarter of 2016, but increased to 21 drilling rigs operatingbook value at the end of 2016. Our drilling rig count continued to increaseeach period, adjusted for any contributions made and distributions received during the first three quartersperiod.

Warrants

Each holder of 2017Unit common stock outstanding (Old Common Stock) before the September 3, 2020 emergence from bankruptcy (Emergence Date) that did not opt out of the release under the Chapter 11 plan of reorganization filed with the bankruptcy court on June 9, 2020 is entitled to 36 drilling rigs duringreceive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant is exercisable for one share of company common stock, subject to adjustment as provided in the third quarter but we endedWarrant Agreement. The warrants expire on the third quarter with 33 operating drilling rigs. The future demandearliest of (i) September 3, 2027, (ii) consummation of a Cash Sale (as defined in the Warrant Agreement), or (iii) the consummation of a liquidation, dissolution or winding up of the company. As of June 30, 2022, the company has issued 1,822,203 warrants. See Note 5 - Capital Stock for additional discussion on warrant provisions.

Pursuant to the terms of the Warrant Agreement, the company determined the initial exercise price of the warrants to be $63.74. On April 7, 2022, the company delivered notice of the initial exercise price to the Warrant Agent 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 upwarrants became exercisable 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 termshares of the contract. Duringcompany’s common stock. On or about April 25, 2022, the first nine months of 2017, we recorded $0.8 million of early termination fees compared to $3.1 million inwarrants began trading over-the-counter under the first nine months of 2016.symbol "UNTCW".


All ten of our existing BOSS drilling rigs are under contract. Three stacked Mid-Continent SCR drilling rigs were returned to service in the third quarter. One was relocated from our Rocky Mountain division. Three SCR rigs also completed their contracts during the quarter. Our estimated 2017 capital expenditures for this segment are approximately $38.0 million.

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

Mid-Stream

Third quarter 2017 liquids sold per day increased 1% over the second quarter of 2017 and decreased 5% from the third quarter of 2016, respectively. The increase over the second quarter of 2017 was due to increased volumes available to our processing facilities. The decrease from the third quarter of 2016 was primarily due to less volume available to process at our plants. For the third quarter of 2017, gas processed per day increased 4% over the second quarter of 2017 and decreased 8% from the third quarter of 2016. The increase over the second quarter of 2017 was primarily due to higher processed volumes from new wells at our Cashion facility and our Hemphill facility. The decrease from the third quarter of 2016 was primarily due to declines in existing volumes, fewer new wells connected, and no offload volume at our Hemphill facility in 2017. For the third quarter of 2017, gas gathered per day was essentially unchanged and decreased 11% from the second quarter of 2017 and the third quarter of 2016, respectively. The decrease from the third quarter of 2016 was primarily due to declining gathered volume on our Appalachian gathering systems.

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

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

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

We connected the new Allen well pad in May and it included five new wells. We did not connect any new wells in the third quarter. We are constructing a pipeline to connect the Miller well pad, which will be the next pad connected to our system. The Miller pad will include seven new wells and we anticipate it will be ready to flow in the third quarter of 2018. Also, we anticipate several in-fill wells to be drilled and connected to our system in the second half of 2018.

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

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

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

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

Our estimated 2017 capital expenditures for this segment are approximately $18.9 million.

Financial Condition and Liquidity


Summary


Our near-term and long-term financial condition and liquidity dependsprimarily depend on the cash flow from our operations and borrowings undercredit agreement borrowings. The principal factors determining our credit agreement. Our cash flow is based primarily on:from operations 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 forutilization of our drilling rigs and the dayratesrates we receive for ourthose drilling rigs; and
37
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•the fees and margins we obtainthat Superior obtains from ourits natural gas gathering and processing contracts.


We believe we will have enoughexpect that cash and cash equivalents, cash flow from operations, and liquidityavailable borrowing capacity under the Exit credit agreement will be adequate to meetsupport our obligationsworking capital, capital expenditures, potential dividend distributions, discretionary stock repurchases, and remain in compliance with our debt covenantsother cash requirements for at least the next 12 months and we are not aware of any indications that they will not be adequate for the next twelve months. Our abilityforeseeable periods thereafter.

The table below summarizes cash flow activity during the periods indicated:

 Six Months Ended June 30,
Percent
Change (1)
 20222021
 (In thousands except percentages)
Net cash provided by operating activities$88,125 $73,965 19 %
Net cash provided by (used in) investing activities(13,882)7,605 NM
Net cash used in financing activities(22,755)(87,295)74 %
Net increase (decrease) in cash and cash equivalents$51,488 $(5,725)
1.NM - A percentage calculation is not meaningful due to meet our debt covenants (under our credit agreement and our 2011 Indenture) and our capacity to incur additional indebtedness will depend on our future performance, which will be affected by financial, business, economic, regulatory, and other factors. For example, if we experience lower oil, natural gas, and NGLs prices since the last borrowing base determination under our credit agreement, it could cause a reduction of the borrowing base and therefore reducezero-value denominator or limit our ability to incur indebtedness. We monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues, and work, where possible, with our lenders to address those issues ahead of time.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 quantityvolume of oil, NGLs, and natural gas we produce, settlements of commodity derivative contracts, and third-party demand forutilization of our drilling rigs and Superior's mid-stream services, and the rates we obtaincharged for those drilling and mid-stream services. Our cash flows from operating activities are also impactedaffected by changes in working capital.


Net cash provided by operating activities induring the first ninesix months of 2017 decreased2022 increased by $13.0$14.2 million as compared to the first ninesix months of 2016. The decrease was the result of2021 primarily due to increased operating profit from our oil and natural gas and contract drilling segments, partially offset by higher payments on derivative settlements, net changes in operating assets and liabilities related to the timing of cash receipts and disbursements, partially offset by higherand lower operating profit margins in all three segments.from our mid-stream segment reflecting the March 1, 2022 deconsolidation of Superior.


Cash Flows from Investing Activities


We dedicate and expect to continue to dedicateanticipate using a substantial portion of our free cash flows for capital budgetexpenditures related to the exploration forour development and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells.


Cash flows used inNet cash provided by (used in) investing activities increaseddecreased by $96.7$21.5 million forduring the first ninesix months of 20172022 compared to the first ninesix months of 2016. The change was2021 primarily due primarily to an increase inthe deconsolidation of Superior's cash and cash equivalents, higher 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 thelower proceeds received from the disposition of non-core assets. See additional information on capital expenditures below under Capital Requirements.


Cash Flows from Financing Activities


Cash flows provided byNet cash used in financing activities increaseddecreased by $109.5$64.5 million for the first ninesix months of 20172022 compared to the first ninesix months of 2016. The increase was2021 primarily due to proceeds from the ATMabsence of net payments on credit agreements and finance leases as well as lower distributions made by Superior to non-controlling interests, partially offset by higher repurchases of common stock. A portion of future cash flows and cash and cash equivalents may be used for future shareholder return activities, including stock programrepurchases and an increase in book overdrafts in 2017 coupled with almost no change in net borrowing after paying down long-term debt in 2016.cash distributions.


At SeptemberAs of June 30, 2017,2022, we had unrestricted cash and cash equivalents totaling $0.8$115.6 million and had borrowed $162.1 millionno outstanding borrowings under the Exit credit agreement.

38
Table of the $475.0 million we had elected to then have available under our credit agreement. Our credit agreement is used primarily for working capital and capital expenditures.Contents

The following is a summary oftable summarizes certain financial condition and liquidity information as of September 30, 2017 and 2016 and for the nine months ended September 30, 2017 and 2016:dates identified below:


 June 30,
2022		June 30,
2021
 (In thousands)
Working capital$79,799 $(38,200)
Current portion of long-term debt$— $— 
Long-term debt$— $35,000 
Shareholders’ equity attributable to Unit Corporation$260,368 $155,562 
  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, ourOur working capital balance typically fluctuates in part, because ofdue to the timing of our trade accounts receivable and accounts payable, and the fluctuation in current assets and liabilities associated with the mark to market valuefair values of our derivative activity.positions. We had positive working capital of $79.8 million and negative working capital of $62.2 million and $42.3$38.2 million as of SeptemberJune 30, 20172022 and 2016,2021, respectively. The increase in negative working capital is primarily due to increasedincreases in cash and cash equivalents and accounts payable due to increased activity in our drilling programreceivable, net as well as the absence of the warrant liability and increased drilling rig utilizationlower accrued liabilities and the reclassification of current deferred tax asset to long-term asset per ASU 2015-17payables, partially offset by increased accounts receivable from increased revenues and the change in the value of outstanding derivatives.higher current commodity derivative liabilities. 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. The effect of ourcommodity derivative contracts increaseddecreased working capital by $0.4$48.8 million as of SeptemberJune 30, 20172022 and decreased working capital by $5.6$38.0 million as of SeptemberJune 30, 2016.2021.


The following table summarizes certain operating information: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 we have atproceeds from the enddisposition of each quarter:certain assets be used to repay amounts outstanding.


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, among others, 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.

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.

On March 30, 2022, the RBL Facility borrowing base of $80.0 million was reaffirmed.

On July 1, 2022, the RBL Facility borrowing base was automatically reduced to $31.3 million as a result of closing the Texas Gulf Coast properties sale discussed in Note 4 - Divestitures.

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 credit agreement) for the most recently ended rolling four quarters of no greater than 2.75 to 1.

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

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

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

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

The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for issuing the Notes. The Guarantors are most of our direct and indirect subsidiaries. The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.

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

We may redeem all or, occasionally, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions we must offer(Superior credit agreement). On April 29, 2022, Superior entered into an Amended and Restated Credit Agreement for a four-year, $135.0 million senior secured revolving credit facility with an option to repurchase from each holder all or any partincrease the credit amount up to $200.0 million, subject to certain conditions (Amended Superior credit agreement).

39
Table 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.Contents

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 16 gross wells (15.10(0.64 net wells) indrilled by other operators during the first ninesix months of 20172022 compared to 1510 gross wells (7.77(0.77 net wells) induring the first ninesix months of 2016.2021.

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 forincluding oil and gas properties on the full cost method for the first ninesix months of 20172022 by this segment totaled $9.2 million, excluding $56.4a $1.4 million for acquisitions and a $2.8 millionincrease in the ARO liability, totaled $143.7 million. Capital expenditures for the first nine months of 2016,compared to $5.9 million, excluding a $29.4$1.1 million reduction in the ARO liability, totaled $91.9 million.during the first six months of 2021.


We planOn July 1, 2022, the company closed on the sale of certain wells and related leases near the Texas Gulf Coast for cash proceeds of $43.7 million, subject to participatecustomary post-closing adjustments based on an effective date of April 1, 2022. These proceeds will reduce the net book value of our full cost pool with no gain or loss recognized as the sale did not result 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 drilla significant alteration of the full numbercost pool.

On March 8, 2022, the company closed on the sale of certain non-core wells planned dependsand related leases located near the Oklahoma Panhandle for cash proceeds of $4.1 million net of customary closing and post-closing adjustments based on several factors, manyan effective date of which are beyondDecember 1, 2021. These proceeds reduced the net book value of our control, includingfull cost pool with no gain or loss recognized as the availabilitysale did not result in a significant alteration of drilling rigs, availabilitythe full cost pool.

On May 6, 2021, the company closed on the sale of pressure pumping services, pricessubstantially all of our wells and the leases related thereto located in Reno and Stafford Counties, Kansas for proceeds of $7.1 million, excluding post-closing adjustments. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool.

Net proceeds for the sale of other non-core oil NGLs, and natural gas demand for oil, NGLs,assets totaled $2.3 million and natural gas,$4.4 million during the six months ended June 30, 2022 and 2021, respectively. These proceeds reduced the net book value of our full cost to drill wells,pool with no gain or loss recognized as the weather, andsales did not result in a significant alteration of the efforts of outside industry partners.full cost pool.


Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. DuringNear term capital expenditures are expected to primarily be for maintenance capital on operating drilling rigs. We also continue to pursue the disposal or sale of our non-core, idle drilling rig fleet. Contract drilling capital expenditures totaled $4.2 million during the first quartersix months of 2017, we were awarded a term2022 compared to $0.5 million during the first six months of 2021.

We sold non-core contract to build our tenth BOSS rig. Construction was completeddrilling assets for proceeds of $6.4 million 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 overduring the next year. We have spent $30.0six months ended June 30, 2022 and 2021, respectively. These proceeds resulted in net gains of $4.2 million forand $2.1 million during the six months ended June 30, 2022 and 2021, respectively.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. Superior incurred $1.2 million in consolidated capital expenditures during the first ninesix months of 2017,2022 compared to $7.2$4.1 million for capital expenditures during the first ninesix months of 2016.2021. 

Mid-Stream 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, our mid-stream segment incurred $10.1 million in capital expenditures as compared to $11.1 million in the first nine months of 2016. For 2017, our estimated capital expenditures are approximately $18.9 million.


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
 $—
40
_______________________
(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
Table of Contents
_______________________ 
(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.








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 SeptemberAs of June 30, 2017,2022, based on our thirdsecond quarter 20172022 average daily production, the approximated percentages of our production under derivative contracts are as follows:
20222023
Daily oil production86%45%
Daily natural gas production75%36%

  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 toUsing 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 itinstruments involves the risk that the counterparties may not be able tocannot meet theirthe financial obligations underterms of the transactions. Based on our September 30, 2017 evaluation, we believe theWe considered this non-performance risk of non-performance byregarding our counterparties is not material. At Septemberand our own non-performance risk in our derivative valuation at June 30, 2017, the2022 and determined there was no material risk at that time. The fair valuesvalue of the net assets (liabilities)liabilities we had with eachBank of Oklahoma, our only commodity derivative counterparty, was $66.1 million as of June 30, 2022.

Warrants. Prior to the determination of the counterparties to our commodity derivative transactions are as follows:
  September 30, 2017
  (In millions)
Bank of Montreal $0.9
Scotiabank (0.1)
Canadian Imperial Bank of Commerce (0.3)
Bank of America (0.4)
Total assets $0.1

If a legal right of set-off exists,initial exercise price, 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 recordedrecognized the fair value of our commodity derivativesthe warrants as a derivative liability on our unaudited condensed consolidated balance sheetsheets with changes in the liability reported 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 thegain (loss) on change in fair value of our commodity derivatives on our balance sheet as non-current derivative assets of $0.4 million, and current and non-current derivative liabilities of $21.6 million and $0.4 million, respectively.

For our economic hedges any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations. These gains (losses) at September 30 are as follows:
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
  (In thousands)
Gain (loss) on derivatives:        
Gain (loss) on derivatives, included are amounts settled during the period of $840, ($457), ($729) and $11,735, respectively $(2,614) $6,969
 $21,019
 $(4,774)
  $(2,614) $6,969
 $21,019
 $(4,774)

Stock and Incentive Compensation

During the first nine months of 2017, we granted awards covering 698,276 shares of restricted stock. These awards had an estimated fair value as of their grant date of $17.2 million. Compensation expense will be recognized over the three year vesting periods, and during the nine months of 2017, we recognized $5.0 million in compensation expense and capitalized $0.8 million for these awards. During the first nine months of 2017, we recognized compensation expense of $9.0 million for all of

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

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

Insurance

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

Oil and Natural Gas Limited Partnerships and Other Entity Relationships

We are the general partner of 13 oil and natural gas partnerships which were formed privately or publicly. Each partnership’s revenues and costs are shared under formulas set out in that partnership’s agreement. The partnerships repay us for contract drilling, well supervision, and general and administrative expense. Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed on the same basis as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party’s behalf as well as indirect expenses assigned to the related parties. Allocations are based on the related party’s level of activity and are considered by us to be reasonable. For the first nine months of 2017 and 2016, the total we received for all of these fees was $0.1 million and $0.2 million, respectively. Our proportionate share of assets, liabilities, and net income (loss) relating to the oil and natural gas partnerships is includedwarrants 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 changesstatements of operations. On April 7, 2022, the company delivered notice of the initial $63.74 exercise price resulting in the terms and conditions of a share-based payment award. The amendments are effective for reporting periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements.

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

Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifyingwarrants meeting 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,an equity instrument. Accordingly, we recognized 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 classifiedchange 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 principlefair value of the amendments is that an entity should recognize revenuewarrant liability in our unaudited condensed consolidated statements of operations and reclassified the $49.1 million warrant liability to depictcapital in excess of par value on the transferunaudited condensed consolidated balance sheets as of promised goods or services to customers in an amount that reflects the consideration to which the entity expectsApril 7, 2022. The warrants will continue to be entitledreported as capital in exchange for those goodsexcess of par and are no longer subject to future fair value adjustments. On or services. ASU 2014-09 has been amended several times pre-issuance, which will be codified inabout April 25, 2022, the new Topic 606, and itwarrants began trading over-the-counter under the symbol "UNTCW".

Below 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 effectderivative instruments on our statementthe unaudited condensed consolidated statements of operations or our balance sheet, asfor the timingperiods indicated:

Three Months Ended June 30,Six Months Ended June 30,
2022202120222021
 (In thousands)
Gain (loss) on derivatives$2,609 $(42,400)$(61,467)$(65,231)
Cash settlements paid on commodity derivatives(32,884)(6,403)(54,123)(9,707)
Gain (loss) on derivatives less cash settlements paid on commodity derivatives$35,493 $(35,997)$(7,344)$(55,524)
Gain (loss) on change in fair value of warrants$7,289 $(3,574)$(29,323)$(3,574)

41
Table 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:Contents

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 SeptemberThree months ended June 30, 20172022 versus Quarter Ended Septemberthree months ended June 30, 20162021
Provided below is a comparison of selected operating and financial data:
 Three Months Ended June 30,Change
Percent
Change (1)
 20222021
(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations$134,538 $144,160 $(9,622)(7)%
Total revenue, after inter-segment eliminations$134,554 $134,057 $497 — %
Net income (loss)$80,093 $(10,115)$90,208 NM
Net income (loss) attributable to non-controlling interest$— $2,879 $(2,879)(100)%
Net income (loss) attributable to Unit Corporation$80,093 $(12,994)$93,087 NM
Oil and Natural Gas:
Revenue, before inter-segment eliminations$100,896 $59,776 $41,120 69 %
Operating costs, before inter-segment eliminations$27,603 $16,350 $11,253 69 %
Average oil price (Bbl)$56.28 $48.38 $7.90 16 %
Average oil price excluding derivatives (Bbl)$110.29 $64.38 $45.91 71 %
Average NGLs price (Bbl)$34.72 $17.95 $16.77 93 %
Average NGLs price excluding derivatives (Bbl)$34.72 $17.95 $16.77 93 %
Average natural gas price (Mcf)$4.24 $2.98 $1.26 42 %
Average natural gas price excluding derivatives (Mcf)$6.62 $3.00 $3.62 121 %
Oil production (MBbls)309��389 (80)(21)%
NGL production (MBbls)620 662 (42)(6)%
Natural gas production (MMcf)6,821 7,543 (722)(10)%
Contract Drilling:
Revenue, before inter-segment eliminations$33,642 $18,061 $15,581 86 %
Operating costs, before inter-segment eliminations$25,763 $14,080 $11,683 83 %
Average number of drilling rigs in use16.3 10.0 6.3 63 %
Total drilling rigs available for use at the end of the period21 21 — — %
Average dayrate on daywork contracts - BOSS Rigs$21,955 $20,063 $1,892 9 %
Average dayrate on daywork contracts - SCR Rigs$18,217 $14,034 $4,183 30 %
Mid-Stream: (2)
Revenue, before inter-segment eliminations$— $66,323 $(66,323)(100)%
Operating costs, before inter-segment eliminations$— $55,176 $(55,176)(100)%
Corporate and Other:
General and administrative expense, before inter-segment eliminations$7,421 $4,871 $2,550 52 %
Other income (expense):
Interest expense, net$(97)$(487)$390 (80)%
Reorganization items, net$(39)$(1,852)$1,813 (98)%
Gain (loss) on derivatives$2,609 $(42,400)$45,009 106 %
Gain (loss) on change in fair value of warrants$7,289 $(3,574)$10,863 NM
Income tax benefit$— $— $— — %
Average interest rate on long-term debt outstanding— %6.5 %(6.5)%(100)%
Average long-term debt outstanding$— $62,646 $(62,646)(100)%
1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
2.Absence of mid-stream activity during the three months ended June 30, 2022 reflects the March 1, 2022 deconsolidation of Superior.
  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 %
42
_________________________
(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$41.1 million or 8% in69% during the thirdsecond quarter of 20172022 as compared to the thirdsecond 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 20162021 primarily due to higher commodity prices, partially offset by lower production volumes. In the first nine months of 2017, as compared to the first nine months of 2016, oil production decreased 12%, natural gas production decreased 12%, and NGLs production decreased 7%. AverageIncluding derivatives settled, average oil prices increased 23%16% to $47.62$56.28 per barrel, average natural gas prices increased 26%42% to $2.50$4.24 per Mcf, and NGLs prices increased 68%93% to $17.05$34.72 per barrel. Oil production decreased 21%, natural gas production decreased 10%, and NGLs production decreased 6%. 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 increased $3.2$11.3 million or 3%69% between the comparative first nine monthssecond quarters of 20172022 and 20162021 primarily due to increased production taxes on higher LOErevenues, employee separation benefits, and gross production tax partially offset by lower saltwater disposal expense.lease operating expenses.

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$15.6 million or 44% in86% during the first nine monthssecond quarter of 2017 versus2022 compared to the first nine monthssecond quarter of 2016. The increase was2021 primarily due primarily to a 78%an increase in the average number of drilling rigs in use partially offset by a 11% decreasefrom 10.0 in the average dayrate. Average drilling rig utilization increased from 16.7 drilling rigssecond quarter of 2021 to 16.3 in the first nine monthssecond quarter of 20162022 as well as increases to 29.7 drillingthe average dayrates on daywork contracts of 9% and 30% on BOSS 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.and SCR rigs, respectively.


Drilling operating costs increased $24.7$11.7 million or 37%83% between the comparative first nine monthssecond quarters of 20172022 and 2016. The2021 primarily due to an increase was due primarily to more drillingin the average number of operating rigs operating. Contract drilling depreciation increased $7.5as well as $2.3 million or 22% also due primarily to more drillingof transportation and start up costs associated with bringing stacked rigs operating.back into service.


Mid-Stream


Our mid-stream revenues increased $17.7decreased $66.3 million or 13% in100% during the first nine monthssecond quarter of 20172022 as compared to the first nine monthssecond quarter of 2016 due primarily to increased gas, NGLs, and condensate prices partially offset by a decrease in gas processed volumes. Gas processed volumes per day decreased 16% between the comparative periods primarily2021 due to declines in existing volumes, fewer new wells connected, and no offload volume at our Hemphill facility in 2017. Gas gathered volumes per day decreased 8% between the comparative periods primarily due declines in existing volumes, fewer new wells connected, and no offload volume at our Hemphill facility in 2017.absence of activity as a result of the March 1, 2022 deconsolidation of Superior.


Operating costs increased $12.7decreased $55.2 million or 13% in100% during the first nine monthssecond quarter of 20172022 compared to the first nine monthssecond quarter of 2016 primarily2021 due to increased purchase prices partially offset bythe absence of activity as a decrease in gas purchased volumes. Depreciation and amortization decreased $1.9 million, or 5%, primarily due to certain assets being fully depreciated in 2017.result of the March 1, 2022 deconsolidation of Superior.

Other Depreciation

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


General and Administrative


Corporate general and administrative expenses increased $1.1$2.6 million or 4% in52% during the first nine monthssecond quarter of 20172022 compared to the first nine monthssecond quarter of 20162021 primarily due to higher employee costs.separation benefits.


Gain on Disposition of AssetsInterest Expense, Net

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


Other Income (Expense)


Interest expense, net of capitalized interest, decreased $1.4$0.4 million between the comparative first nine monthssecond quarters of 20172022 and 20162021 primarily due primarily to a 8%100% 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.outstanding. Our average interest rate increased from 5.6% to 6.0% and our average debt outstanding was $71.2decreased $62.6 million lower induring the first nine monthssecond quarter of 2017 as2022 compared to the first nine monthssecond quarter of 20162021 primarily due to payments made under the decrease in outstanding borrowings under ourExit credit agreement overand the comparative periods.deconsolidation of Superior's outstanding long-term debt.


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.

Gain (Loss) on Derivatives


GainThe $45.0 million favorable change in gain (loss) on derivatives increased $25.8 millionbetween the comparative second quarters of 2022 and 2021 is primarily due to fluctuationsfavorable pricing changes on unsettled commodity derivative positions and new commodity derivative positions executed during the second quarter of 2022, partially offset by higher settlement payments driven by higher average pricing.

43
Loss on Change in forward pricesFair Value of Warrants

The $10.9 million favorable change in gain (loss) on change in fair value of warrants between the comparative second quarters of 2022 and 2021 is primarily due to changes in the underlying assumptions used to estimate the fair value, in mark-to-market accounting.including entity value, volatility, duration to exercise, and other inputs.


Income Tax Benefit

We did not record an income tax benefit during the second quarter of 2022 or during the second quarter of 2021 due to the company's full valuation allowance against our net deferred tax asset.

44

Six months ended June 30, 2022 versus six months ended June 30, 2021
Provided below is a comparison of selected operating and financial data:
 Six Months Ended June 30,Change
Percent
Change (1)
 20222021
(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations$334,200 $274,468 $59,732 22 %
Total revenue, after inter-segment eliminations$322,919 $254,954 $67,965 27 %
Net income (loss)$27,388 $(10,706)$38,094 NM
Net income (loss) attributable to non-controlling interest$(5,828)$4,225 $(10,053)NM
Net income (loss) attributable to Unit Corporation$33,216 $(14,931)$48,147 NM
Oil and Natural Gas:
Revenue, before inter-segment eliminations$188,478 $114,801 $73,677 64 %
Operating costs, before inter-segment eliminations$51,603 $36,343 $15,260 42 %
Average oil price (Bbl)$58.23 $47.82 $10.41 22 %
Average oil price excluding derivatives (Bbl)$100.03 $60.12 $39.91 66 %
Average NGLs price (Bbl)$33.82 $17.95 $15.87 88 %
Average NGLs price excluding derivatives (Bbl)$33.82 $17.95 $15.87 88 %
Average natural gas price (Mcf)$3.78 $2.87 $0.91 32 %
Average natural gas price excluding derivatives (Mcf)$5.60 $2.86 $2.74 96 %
Oil production (MBbls)714 801 (87)(11)%
NGL production (MBbls)1,233 1,303 (70)(5)%
Natural gas production (MMcf)13,336 14,946 (1,610)(11)%
Contract Drilling:
Revenue, before inter-segment eliminations$62,524 $33,735 $28,789 85 %
Operating costs, before inter-segment eliminations$52,000 $25,951 $26,049 100 %
Average number of drilling rigs in use15.9 9.7 6.2 64 %
Total drilling rigs available for use at the end of the period21 21 — — %
Average dayrate on daywork contracts - BOSS Rigs$21,344 $20,197 $1,147 6 %
Average dayrate on daywork contracts - SCR Rigs$17,119 $13,651 $3,468 25 %
Mid-Stream: (2)
Revenue, before inter-segment eliminations$83,198 $125,932 $(42,734)(34)%
Operating costs, before inter-segment eliminations$73,711 $104,286 $(30,575)(29)%
Gas gathered--Mcf/day348,859 296,396 52,463 18 %
Gas processed--Mcf/day146,368 124,285 22,083 18 %
Gas liquids sold--gallons/day456,700 425,277 31,423 7 %
Corporate and Other:
General and administrative expense, before inter-segment eliminations$13,336 $11,160 $2,176 19 %
Other income (expense):
Interest expense, net$(371)$(2,777)$2,406 (87)%
Reorganization items, net$(42)$(2,988)$2,946 99 %
Loss on derivatives$(61,467)$(65,231)$3,764 6 %
Loss on change in fair value of warrants$(29,323)$(3,574)$(25,749)NM
Loss on deconsolidation of Superior$(13,141)$— $(13,141)— %
Income tax benefit$— $— $— — %
Average interest rate on long-term debt outstanding2.2 %6.7 %(4.5)%(68)%
Average long-term debt outstanding$6,338 $77,852 $(71,514)(92)%
1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
2.Mid-Stream activity and metrics shown in this table for the six months ended June 30, 2022 reflect Superior activity on a consolidated basis for the two months prior to March 1, 2022.
45
Oil and Natural Gas

Oil and natural gas revenues increased $73.7 million or 64% during the first six months of 2022 as compared to the first six months of 2021 primarily due to higher commodity prices, partially offset by lower production volumes. Including derivatives settled, average oil prices increased 22% to $58.23 per barrel, average natural gas prices increased 32% to $3.78 per Mcf, and NGLs prices increased 88% to $33.82 per barrel. Oil production decreased 11%, natural gas production decreased 11%, and NGLs production decreased 5%. 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 increased $15.3 million or 42% between the comparative first six months of 2022 and 2021 primarily due to increased production taxes on higher revenues, higher lease operating expenses, and employee separation benefits.

Contract Drilling

Drilling revenues increased $28.8 million or 85% during the first six months of 2022 compared to the first six months of 2021 primarily due to an increase in the average number of rigs in use from 9.7 during the first six months of 2021 to 15.9 during the first six months of 2022 as well as increases to the average dayrates on daywork contracts of 6% and 25% on BOSS rigs and SCR rigs, respectively.

Drilling operating costs increased $26.0 million or 100% between the comparative first six months of 2022 and 2021 primarily due to an increase in the average number of operating rigs as well as $6.6 million of transportation and start up costs associated with bringing stacked rigs back into service.

Mid-Stream

Our mid-stream revenues decreased $42.7 million or 34% during the first six months of 2022 as compared to the first six months of 2021 primarily due to the absence of activity subsequent to March 1, 2022 as a result of the deconsolidation of Superior, partially offset by higher gas, NGL, and condensate prices as well as higher volumes during the consolidated period. Gas processed volumes per day increased 18% while gas gathered volumes per day increased 18% between the comparative first six months of 2022 and 2021 primarily due to connecting new wells as well as new volumes from the processing plant and gathering system acquired in November 2021.

Operating costs decreased $30.6 million or 29% during the first six months of 2022 compared to the first six months of 2021 primarily due to the absence of activity subsequent to March 1, 2022 as a result of the deconsolidation of Superior, partially offset by higher gas, NGL, and condensate prices as well as higher purchase volumes related to the processing plant and gathering system acquired in November 2021.

General and Administrative

Corporate general and administrative expenses increased $2.2 million or 19% during the first six months of 2022 as compared to the first six months of 2021 primarily due to employee separation benefits.

Interest Expense, (Benefit)Net


Income taxInterest expense, increased $95.2net decreased $2.4 million between the comparative first ninesix months of 20172022 and 20162021 primarily due to increased pre-tax income. Our effective taxa 92% decrease in average long-term debt outstanding and a decrease in the average interest rate was 43.5% forfrom 6.7% during the first ninesix months of 20172021 to 2.2% during the first six months of 2022. Our average debt outstanding decreased $71.5 million during the first six months of 2022 compared to 34.8% for the first ninesix months of 2016. The increase was2021 primarily due to increased deferred tax expense relatedpayments made under the Exit credit agreement and the deconsolidation of Superior's outstanding long-term debt, partially offset by borrowings under the Superior credit agreement prior to our restricted stock vestingsdeconsolidation.

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.

46
Gain (Loss) on Derivatives

The $3.8 million favorable change in bothgain (loss) on derivatives between the comparative periods. There was no current income tax expense or benefitfirst six months of 2022 and 2021 is primarily due to less unfavorable pricing changes on unsettled commodity derivative positions and new commodity derivative positions executed during the second quarter of 2022, partially offset by higher settlement payments driven by higher average pricing.

Loss on Change in Fair Value of Warrants

The $25.7 million unfavorable change in loss on change in fair value of warrants between the comparative second quarters of 2022 and 2021 is primarily due to changes in the underlying assumptions used to estimate the fair value, including entity value, volatility, duration to exercise, and other inputs.

Loss on Deconsolidation of Superior

Loss on deconsolidation of $13.1 million during the first ninesix months of 2017 or 2016. 2022 represents the loss recognized on the March 1, 2022 deconsolidation of Superior.

Income Tax Benefit

We did not pay anyrecord an income taxes intax benefit during first six months of 2022 or during the first ninesix months of 2017.2021 due to the company's full valuation allowance against our net deferred tax asset.


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 ninesix months 2017of 2022 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$0.2 million per month ($4.82.6 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 ($2.51.4 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 ($4.52.5 million annualized) change in our pre-tax operating cash flow.


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


At September
47
As of June 30, 2017,2022, we had the following commodity derivatives were outstanding:

TermCommodityContracted Volume
Weighted Average 
Fixed Price for Swaps
Contracted Market
Oct'17Jul'22 - Dec'22Natural gas –- swap70,0005,000 MMBtu/day$3.0382.61IF –- NYMEX (HH)
Nov’17 – Dec'17Jul'22 - Feb'23Natural gas –- swap60,00018,765 MMBtu/day$2.9609.14IF –- NYMEX (HH)
Jan’18 – Dec'18Jan'23 - Dec'23Natural gas –- swap20,00022,000 MMBtu/day$3.0132.46IF –- NYMEX (HH)
Nov’17 – Dec'17Jul'22 - Dec'22Natural gas – basis swap- collar20,00035,000 MMBtu/day$(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$2.68IF - $3.32IF – NYMEX (HH)
Nov’17 – Dec'17Jul'22 - Dec'22Natural gas – three-way collarCrude oil - swap25,000 MMBtu/2,300 Bbl/day$2.9042.25WTI - $2.30 - $3.59IF – NYMEX (HH)
Jan'18 – Mar'18Jul'22 - Dec'22Natural gas – three-way collarCrude oil - swap60,000 MMBtu/596 Bbl/day$3.29103.98WTI - $2.63 - $4.07IF – NYMEX (HH)
Apr'18 – Dec'18Jan'23 - Feb'23Natural gas – three-way collarCrude oil - swap20,000 MMBtu/1,339 Bbl/day$3.0095.40WTI - $2.50 - $3.51IF – NYMEX (HH)
Oct’17 – Dec'17Jan'23 - Dec'23Crude 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 as its borrowings carry variable interest rates. We had no outstanding borrowings under this facility as of June 30, 2022. See Note 9 – Long-Term Debt and the Notes. The credit agreement, at our election bears interest at variable rates basedOther Long-Term Liabilities for more information on the Prime Rate or the LIBOR Rate. At our election, borrowings under ourExit credit agreement may be fixed at the LIBOR Rate for periods of up to 180 days. Based on our average outstanding long-term debt subject to a variable rate in the first nine months of 2017, a 1% increase in the floating rate would reduce our annual pre-tax cash flow by approximately $1.6 million. Under our Notes, we pay a fixed rate of interest of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year).agreement.



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 (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 internal control over financial reporting and make modifications as necessary; our intent in this regard is that the Disclosure Controls and internal control over financial reporting 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 Officer and Chief Financial Officer,CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures under Exchange Act Rule 13a-15. Based on that evaluation, our Chief Executive OfficerCEO and Chief Financial OfficerCFO concluded that our disclosure controls and procedures arewere effective as ofSeptember June 30, 2017 in ensuring the appropriate information is recorded, processed, summarized and reported in our periodic SEC filings relating to the company (including its consolidated subsidiaries) and is accumulated and communicated to the Chief Executive Officer, Chief Financial Officer, and management to allow timely decisions.2022.


Changes in Internal Controls. In January 2017, we implemented a new ERP accounting and reporting system designed to upgrade our technology and improve the timeliness and quality of our financial and operational information. This new ERP system was not implemented in response to any material weakness There were no changes in our internal control over financial reporting (ICFR). The implementation of the ERP system has affected the processes that constitute part of our ICFR and requires ongoing testing for effectiveness. The adoption of this new ERP system has not materially affected our ICFR. There were no changes in ICFR during the quarter ended SeptemberJune 30, 2017,2022, that materially affected, our ICFR or are reasonably likely to materially affect, it, as defined in Rule 13a – 15(f) under the Exchange Act.our internal control over financial reporting.


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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 16 – 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, 2016,2021, 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, 2016.2021.


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

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

Although we believe that the allegations in these lawsuits are without merit and intend to defend such litigation vigorously, litigation is subject to inherent uncertainties, and an adverse result in one of these lawsuits or other matters that may arise from time to time could have a material adverse effect on our business, results of operations and financial condition. Defending the lawsuits may be costly and, further, could require significant involvement of our senior management and may divert management's attention from our business and operations.

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


In June 2021, we repurchased an aggregate of 600,000 shares of our 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 our 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. The Board subsequently authorized increases to the authorized repurchases up to $50.0 million in October 2021 and then up to $100.0 million in June 2022. 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 June 30, 2022, we had repurchased a total of 1,519,392 shares under the repurchase program at an average share price of $36.00 for an aggregate purchase price of $54.7 million. Subsequent to June 30, 2022, we have repurchased an additional 75,000 shares under the repurchase program for an aggregate purchase price of $3.8 million.

During the year ended December 31, 2021, we also repurchased 78,000 shares in a privately negotiated transaction at a share price of $19.07 which were not part of the repurchase program.

The cumulative number of shares repurchased as of June 30, 2022 totaled 2,197,392. The cash purchase price and any direct acquisition costs are reflected as treasury stock on the unaudited condensed consolidated balance sheets as of June 30, 2022.

The following table provides information relating to ourbelow shows share repurchase of common stockactivity for the three months ended SeptemberJune 30, 2017:2022:
Period
(a)
Total Number of Shares Purchased
(b)
Average Price Paid
Per Share
(c)
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs
(d)
Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
July 1, 2017 to July 31, 2017—
$—
—
—
August 1, 2017 to August 31, 2017—
—
—
—
September 1, 2017 to September 30, 2017—
—
—
—
Total—
$—
—
—


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)
April 1, 2022 through April 30, 2022— $— — $8,570 
May 1, 2022 through May 31, 2022— $— — $8,570 
June 1, 2022 through June 30, 2022247,429 $53.63 247,429 $45,300 
1.Reflects the June 2022 increase to authorized repurchases from $50.0 million to $100.0 million.

Item 3. Defaults Upon Senior Securities


Not applicable.

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Item 4. Mine Safety Disclosures


Not applicable.



Item 5. Other Information


Not applicable.




Item 6. Exhibits


Exhibits:
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).



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SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Unit Corporation
Date:Unit Corporation
Date:November 2, 2017August 11, 2022
By: /s/ Larry D. PinkstonPhilip B. Smith
LARRY D. PINKSTONPHILIP B. SMITH
President and Chief Executive Officer and Director
Date:November 2, 2017August 11, 2022
By: /s/ David T. MerrillThomas D. Sell
DAVID T. MERRILLTHOMAS D. SELL
Chief Operating Officer, Chief Financial Officer
and Treasurer



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