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, 20182019
OR
[ ]☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
[Commission File Number 1-9260]
unt-20190630_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, OklahomaOklahoma 74132
(Address of principal executive offices)(Zip Code)
(918) 493-7700
(Registrant’s telephone number, including area code)
None
(Former name, former address and former fiscal year,
if changed since last report)

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 [  ]                                                     
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Yes [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 [ x ]☒   Accelerated filer [ ]☐    Non-accelerated filer [  ]☐
Smaller reporting company [  ]☐   Emerging growth company [ ]☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]  ☐  


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [  ]☐            No [x]  ☒  
As of OctoberJuly 19, 2018, 54,058,0162019, 55,536,916 shares of the issuer's common stock were outstanding.

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common StockUNTNYSE


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)
43
65
76
87
9
11
Item 2.
4643
Item 3.
7065
Item 4.
7166
PART II. Other Information
Item 1.
7267
Item 1A.
7368
Item 2.
7368
Item 3.
7368
Item 4.
7368
Item 5.
7368
Item 6.
7469
7570


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 addresses activities, events or developments we expect or anticipate will or may occur, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are used to identify forward-looking statements. This report modifies and supersedes documents filed by us before this report. In addition, certain information we file with the SEC will automatically update and supersede information in this report.
These forward-looking statements include, among others, things as:


•the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
•prices for oil, natural gas liquids (NGLs), and natural gas;
•demand for oil, NGLs, and natural gas;
•our exploration and drilling prospects;
•the estimates of our proved oil, NGLs, and natural gas reserves;
•oil, NGLs, and natural gas reserve potential;
•development and infill drilling potential;
•expansion and other development trends of the oil and natural gas industry;
•our business strategy;
•our plans to maintain or increase production of oil, NGLs, and natural gas;
•the number of gathering systems and processing plants we plan to construct or acquire;
•volumes and prices for natural gas gathered and processed;
•expansion and growth of our business and operations;
•demand for our drilling rigs and drilling rig rates;
•our belief that the final outcome of legal proceedings involving us will not materially affect our financial results;
•our ability to timely secure third-party services used in completing our wells;
•our ability to transport or convey our oil or natural gas production to established pipeline systems;
•impact of federal and state legislative and regulatory actions affecting our costs and increasing operating restrictions or delays and other adverse impacts on our business;
•our projected production guidelines for the year;
•our anticipated capital budgets;
•our financial condition and liquidity;liquidity (including our ability to refinance our senior subordinated notes);
•the number of wells our oil and natural gas segment plans to drill or rework during the year; and
our intended use of the proceeds from the sale of 50% of the interest we owned in our mid-stream segment; 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 assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and expected future developments, and other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to several risks and uncertainties, any one or combination of which could cause our actual results to differ materially from our expectations and predictions, including:
•the risk factors discussed in this document and in the documents (if any) we incorporate by reference;
•general economic, market, or business conditions;
•the availability of and nature of (or lack of) business opportunities we pursue;
•demand for our land drilling services;
•changes in laws or regulations;
•changes in the current geopolitical situation;
•risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
•risks associated with future weather conditions;
•decreases or increases in commodity prices;
•putative class action lawsuits that may cause 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 this document to reflect unanticipated events.

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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30,
2019		December 31,
2018
 (In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents$669 $6,452 
Accounts receivable, net of allowance for doubtful accounts of $2,494 and $2,531 at June 30, 2019 and December 31, 2018, respectively 89,876 119,397 
Materials and supplies516 473 
Current derivative asset (Note 10)8,513 12,870 
Income taxes receivable2,405 2,054 
Assets held for sale (Note 3)19,500 22,511 
Prepaid expenses and other9,106 6,602 
Total current assets130,585 170,359 
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties6,212,323 6,018,568 
Unproved properties not being amortized336,214 330,216 
Drilling equipment1,284,295 1,284,419 
Gas gathering and processing equipment798,503 767,388 
Saltwater disposal systems69,212 68,339 
Corporate land and building59,080 59,081 
Transportation equipment30,019 29,524 
Other57,900 57,507 
8,847,546 8,615,042 
Less accumulated depreciation, depletion, amortization, and impairment6,289,575 6,182,726 
Net property and equipment2,557,971 2,432,316 
Goodwill62,808 62,808 
Right of use asset (Note 12)8,302 — 
Other assets33,863 32,570 
Total assets (1)
$2,793,529 $2,698,053 
  September 30,
2018		 December 31,
2017
  (In thousands except share amounts)
ASSETS    
Current assets:    
Cash and cash equivalents $91,557
 $701
Accounts receivable, net of allowance for doubtful accounts of $2,450 at both September 30, 2018 and December 31, 2017, respectively 122,123
 111,512
Materials and supplies 505
 505
Current derivative asset (Note 10) —
 721
Prepaid expenses and other 9,419
 6,233
Total current assets 223,604
 119,672
Property and equipment:    
Oil and natural gas properties on the full cost method:    
Proved properties 5,901,661
 5,712,813
Unproved properties not being amortized 332,886
 296,764
Drilling equipment 1,632,540
 1,593,611
Gas gathering and processing equipment 751,715
 726,236
Saltwater disposal systems 67,074
 62,618
Corporate land and building 59,081
 59,080
Transportation equipment 29,103
 29,631
Other 56,750
 53,439
  8,830,810
 8,534,192
Less accumulated depreciation, depletion, amortization, and impairment 6,325,160
 6,151,450
Net property and equipment 2,505,650
 2,382,742
Goodwill 62,808
 62,808
Other assets 28,703
 16,230
Total assets (1)
 $2,820,765
 $2,581,452


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

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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED


 September 30,
2018		 December 31,
2017		June 30,
2019		December 31,
2018
 (In thousands except share amounts) (In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY    LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:    Current liabilities:
Accounts payable $143,552
 $112,648
Accounts payable$131,129 $149,945 
Accrued liabilities (Note 5) 67,743
 48,523
Accrued liabilities (Note 5)45,175 49,664 
Income taxes payable 1,051
 —
Current derivative liability (Note 10) 13,067
 7,763
Current operating lease liability (Note 12)Current operating lease liability (Note 12)4,519 — 
Current portion of other long-term liabilities (Note 6) 14,150
 13,002
Current portion of other long-term liabilities (Note 6)13,887 14,250 
Total current liabilities 239,563
 181,936
Total current liabilities194,710 213,859 
Long-term debt less debt issuance costs (Note 6) 643,921
 820,276
Long-term debt less debt issuance costs (Note 6)756,590 644,475 
Non-current derivative liability (Note 10) 1,542
 —
Non-current derivative liability (Note 10)256 293 
Operating lease liability (Note 12)Operating lease liability (Note 12)3,556 — 
Other long-term liabilities (Note 6) 101,410
 100,203
Other long-term liabilities (Note 6)102,700 101,234 
Deferred income taxes 164,964
 133,477
Deferred income taxes142,485 144,748 
Commitments and contingencies (Note 12) —
 —
Commitments and contingencies (Note 13)Commitments and contingencies (Note 13)— — 
Shareholders’ equity:    Shareholders’ equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued —
 —
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued— — 
Common stock, $.20 par value, 175,000,000 shares authorized, 54,063,705 and 52,880,134 shares issued as of September 30, 2018 and December 31, 2017, respectively 10,414
 10,280
Common stock, $.20 par value, 175,000,000 shares authorized, 55,536,916 and 54,055,600 shares issued as of June 30, 2019 and December 31, 2018, respectively Common stock, $.20 par value, 175,000,000 shares authorized, 55,536,916 and 54,055,600 shares issued as of June 30, 2019 and December 31, 2018, respectively 10,590 10,414 
Capital in excess of par value 626,746
 535,815
Capital in excess of par value638,769 628,108 
Accumulated other comprehensive income (loss) (Note 14) (103) 63
Accumulated other comprehensive loss (Note 15)Accumulated other comprehensive loss (Note 15)(487)(481)
Retained earnings 830,680
 799,402
Retained earnings741,001 752,840 
Total shareholders’ equity attributable to Unit Corporation 1,467,737
 1,345,560
Total shareholders’ equity attributable to Unit Corporation1,389,873 1,390,881 
Non-controlling interests in consolidated subsidiaries 201,628
 —
Non-controlling interests in consolidated subsidiaries203,359 202,563 
Total shareholders' equity 1,669,365
 1,345,560
Total shareholders' equity1,593,232 1,593,444 
Total liabilities(1) and shareholders’ equity
 $2,820,765
 $2,581,452
Total liabilities(1) and shareholders’ equity
$2,793,529 $2,698,053 
_______________________
(1)Unit Corporation's consolidated total assets as of September 30, 2018 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $41.8 million and $416.7 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of September 30, 2018 include total current and long-term liabilities of the VIE of $38.6 million and $16.1 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 13 – Variable Interest Entity Arrangements.

(1)Unit Corporation's consolidated total assets as of June 30, 2019 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $23.7 million and $435.4 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of June 30, 2019 include total current and long-term liabilities of the VIE of $29.6 million and $21.4 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2018 include total current and long-term assets of the VIE of $40.1 million and $423.3 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2018 include total current and long-term liabilities of the VIE of $42.8 million and $14.7 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 14 – Variable Interest Entity Arrangements.



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



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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED INCOME STATEMENTS OF OPERATIONS (UNAUDITED)
 
Three Months EndedSix Months Ended
 June 30,June 30,
 2019 2018 2019 2018 
 (In thousands except per share amounts)
Revenues:
Oil and natural gas$77,815 $102,318 $163,910 $205,417 
Contract drilling43,037 46,926 94,192 92,915 
Gas gathering and processing44,294 54,059 96,735 110,103 
Total revenues165,146 203,303 354,837 408,435 
Expenses:
Operating costs:
Oil and natural gas36,242 32,418 68,956 68,380 
Contract drilling29,308 31,894 60,709 63,561 
Gas gathering and processing32,491 39,703 71,846 81,307 
Total operating costs98,041 104,015 201,511 213,248 
Depreciation, depletion, and amortization66,292 58,373 128,418 115,439 
General and administrative10,064 8,712 19,805 19,474 
(Gain) loss on disposition of assets(422)(161)1,193 (322)
Total operating expenses173,975 170,939 350,927 347,839 
Income (loss) from operations(8,829)32,364 3,910 60,596 
Other income (expense):
Interest, net(8,995)(7,729)(17,533)(17,733)
Gain (loss) on derivatives7,927 (14,461)995 (21,223)
Other, net6 5 11 11 
Total other income (expense)(1,062)(22,185)(16,527)(38,945)
Income (loss) before income taxes(9,891)10,179 (12,617)21,651 
Income tax expense (benefit):
Deferred(1,874)2,029 (2,318)5,636 
Total income taxes(1,874)2,029 (2,318)5,636 
Net income (loss)(8,017)8,150 (10,299)16,015 
Net income attributable to non-controlling interest492 2,362 1,714 2,362 
Net income (loss) attributable to Unit Corporation$(8,509)$5,788 (12,013)13,653 
Net income (loss) attributable to Unit Corporation per common share (Note 4):
Basic$(0.16)$0.11 $(0.23)$0.26 
Diluted$(0.16)$0.11 $(0.23)$0.26 
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2018 2017 2018 2017
  (In thousands except per share amounts)
Revenues:        
Oil and natural gas $111,623
 $85,470
 $317,040
 $256,241
Contract drilling 50,612
 51,619
 143,527
 128,059
Gas gathering and processing 57,823
 51,399
 167,926
 150,493
Total revenues 220,058
 188,488
 628,493
 534,793
Expenses:        
Operating costs:        
Oil and natural gas 32,139
 33,911
 100,519
 95,873
Contract drilling 32,032
 34,747
 95,593
 91,213
Gas gathering and processing 43,134
 38,116
 124,441
 111,862
Total operating costs 107,305
 106,774
 320,553
 298,948
Depreciation, depletion, and amortization 63,537
 54,533
 178,976
 151,545
General and administrative 9,278
 9,235
 28,752
 26,902
Gain on disposition of assets (253) (81) (575) (1,153)
Total operating expenses 179,867
 170,461
 527,706
 476,242
Income from operations 40,191
 18,027
 100,787
 58,551
Other income (expense):        
Interest, net (7,945) (9,944) (25,678) (28,807)
Gain (loss) on derivatives (4,385) (2,614) (25,608) 21,019
Other, net 6
 5
 17
 14
Total other income (expense) (12,324) (12,553) (51,269) (7,774)
Income before income taxes 27,867
 5,474
 49,518
 50,777
Income tax expense:        
Deferred 6,744
 1,769
 12,380
 22,084
Total income taxes 6,744
 1,769
 12,380
 22,084
Net income 21,123
 3,705
 37,138
 28,693
Net income attributable to non-controlling interest 2,224
 —
 4,586
 —
Net income attributable to Unit Corporation 18,899
 3,705
 32,552
 28,693
Net income attributable to Unit Corporation per common share:        
Basic $0.36
 $0.07
 $0.63
 $0.56
Diluted $0.36
 $0.07
 $0.62
 $0.56


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) (UNAUDITED)
 
Three Months EndedSix Months Ended
 June 30,June 30,
 2019 2018 2019 2018 
 (In thousands) 
Net income (loss)$(8,017)$8,150 $(10,299)$16,015 
Other comprehensive income (loss), net of taxes:
Unrealized gain (loss) on securities, net of tax of ($9), $11, ($2) and ($47) (30)35 (6)(141)
Comprehensive income (loss)(8,047)8,185 (10,305)15,874 
Less: Comprehensive income attributable to non-controlling interest492 2,362 1,714 2,362 
Comprehensive income (loss) attributable to Unit Corporation$(8,539)$5,823 $(12,019)$13,512 
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2018 2017 2018 2017
 (In thousands)
Net income$21,123
 $3,705
 $37,138
 $28,693
Other comprehensive income (loss), net of taxes:       
Unrealized gain (loss) on securities, net of tax of ($13), $20, ($60) and $32(38) 33
 (179) 53
Comprehensive income21,085
 3,738
 36,959
 28,746
Less: Comprehensive income attributable to non-controlling interest2,224
 —
 4,586
 —
Comprehensive income attributable to Unit Corporation$18,861
 $3,738
 $32,373
 $28,746


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 CHANGES IN SHAREHOLDERS’ EQUITY (UNAUDITED)


Three Months Ended June 30, 2019
Shareholders' Equity Attributable to Unit Corporation
Common
Stock		Capital In Excess
of Par Value		Accumulated Other Comprehensive Income (Loss)Retained
Earnings		Non-controlling Interest in Consolidated SubsidiariesTotal
(In thousands except per share amounts)
Balances, March 31, 2019$10,578 $633,361 $(457)$749,510 $202,867 $1,595,859 
Net income (loss)— — — (8,509)492 (8,017)
Other comprehensive loss (net of tax of ($9))— — (30)— — (30)
Total comprehensive loss(8,047)
Activity in employee compensation plans (68,929 shares)12 5,408 — — — 5,420 
Balances, June 30, 2019$10,590 $638,769 $(487)$741,001 $203,359 $1,593,232 

Six Months Ended June 30, 2019
Shareholders' Equity Attributable to Unit Corporation
Common
Stock		Capital In Excess
of Par Value		Accumulated Other Comprehensive Income (Loss)Retained
Earnings		Non-controlling Interest in Consolidated SubsidiariesTotal
 (In thousands except per share amounts)
Balances, December 31, 2018$10,414 $628,108 $(481)$752,840 $202,563 1,593,444 
Cumulative effect adjustment for adoption of ASUs (Notes 1 and 12)— — — 174 — 174 
Net income (loss)— — — (12,013)1,714 (10,299)
Other comprehensive loss (net of tax of ($2))— — (6)— — (6)
Total comprehensive loss(10,305)
Distributions to non-controlling interest— — — — (918)(918)
Activity in employee compensation plans (1,481,316 shares)176 10,661 — — — 10,837 
Balances, June 30, 2019$10,590 $638,769 $(487)$741,001 $203,359 $1,593,232 


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Three Months Ended June 30, 2018 
Shareholders' Equity Attributable to Unit Corporation    Shareholders' Equity Attributable to Unit Corporation
Common
Stock
 
Capital In Excess
of Par Value
 Accumulated Other Comprehensive Income Retained
Earnings		 Non-controlling Interest in Consolidated Subsidiaries TotalCommon
Stock		Capital In Excess
of Par Value		Accumulated Other Comprehensive Income (Loss)Retained
Earnings		Non-controlling Interest in Consolidated SubsidiariesTotal
(In thousands except per share amounts)(In thousands except per share amounts)
Balances, December 31, 2017$10,280
 $535,815
 $63
 $799,402
 $—
 $1,345,560
Cumulative effect adjustment for adoption of ASUs (Notes 1 and 2)—
 —
 13
 (1,274) —
 (1,261)
Balances, March 31, 2018Balances, March 31, 2018$10,403 $541,004 $(100)$805,993 $— $1,357,300 
Net income—
 —
 —
 32,552
 4,586
 37,138
Net income— — — 5,788 2,362 8,150 
Other comprehensive loss (net of tax of ($60))—
 —
 (179) —
 —
 (179)
Other comprehensive gain (net of tax of $11)Other comprehensive gain (net of tax of $11)— — 35 — — 35 
Total comprehensive income          36,959
Total comprehensive income8,185 
Contributions—
 102,958
 —
 —
 197,042
 300,000
Contributions— 102,958 — — 197,042 300,000 
Transaction costs associated with sale of non-controlling interest—
 (2,303) —
 —
 —
 (2,303)Transaction costs associated with sale of non-controlling interest— (2,254)— — — (2,254)
Tax effect of the sale of non-controlling interest—
 (24,300) —
 —
 —
 (24,300)Tax effect of the sale of non-controlling interest— (24,300)— — — (24,300)
Activity in employee compensation plans (1,183,571 shares)134
 14,576
 —
 —
 —
 14,710
Balances, September 30, 2018$10,414
 $626,746
 $(103) $830,680
 $201,628
 $1,669,365
Activity in employee compensation plans (43,005 shares)Activity in employee compensation plans (43,005 shares)11 4,712 — — — 4,723 
Balances, June 30, 2018Balances, June 30, 2018$10,414 $622,120 $(65)$811,781 $199,404 $1,643,654 


Six Months Ended June 30, 2018 
Shareholders' Equity Attributable to Unit Corporation
Common
Stock		Capital In Excess
of Par Value		Accumulated Other Comprehensive Income (Loss)Retained
Earnings		Non-controlling Interest in Consolidated SubsidiariesTotal
 (In thousands except per share amounts)
Balances, December 31, 2017$10,280 $535,815 $63 $799,402 $— $1,345,560 
Cumulative effect adjustment for adoption of ASUs— — 13 (1,274)— (1,261)
Net income— — — 13,653 2,362 16,015 
Other comprehensive loss (net of tax of ($47))— — (141)— — (141)
Total comprehensive income15,874 
Contributions— 102,958 — — 197,042 300,000 
Transaction costs associated with sale of non-controlling interest— (2,254)— — — (2,254)
Tax effect of the sale of non-controlling interest— (24,300)— — — (24,300)
Activity in employee compensation plans (1,209,232 shares)134 9,901 — — — 10,035 
Balances, June 30, 2018$10,414 $622,120 $(65)$811,781 $199,404 $1,643,654 
 Shareholders' Equity Attributable to Unit Corporation    
 
Common
Stock
 
Capital In Excess
of Par Value
 Accumulated Other Comprehensive Income Retained
Earnings		 Non-controlling Interest in Consolidated Subsidiaries Total
 (In thousands except per share amounts)
Balances, December 31, 2016$10,016
 $502,500
 $—
 $681,554
 $—
 $1,194,070
Net income—
 —
 —
 28,693
 —
 28,693
Other comprehensive income (net of tax of $32)—
 —
 53
 —
 —
 53
Total comprehensive income          28,746
Activity in employee compensation plans (1,385,342 shares)261
 28,828
 —
 —
 —
 29,089
Balances, September 30, 2017$10,277
 $531,328
 $53
 $710,247
 $—
 $1,251,905


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





8
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 Nine Months EndedSix Months Ended
 September 30, June 30,
 2018 2017 2019 2018 
 (In thousands) (In thousands)
OPERATING ACTIVITIES:    OPERATING ACTIVITIES:
Net income $37,138
 $28,693
Adjustments to reconcile net income to net cash provided by operating activities:    
Net income (loss)Net income (loss)$(10,299)$16,015 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization 178,976
 151,545
Depreciation, depletion, and amortization128,418 115,439 
Amortization of debt issuance costs and debt discount (Note 6) 1,645
 1,616
Amortization of debt issuance costs and debt discount (Note 6)1,115 1,095 
(Gain) loss on derivatives (Note 10) 25,608
 (21,019)(Gain) loss on derivatives (Note 10)(995)21,223 
Cash payments on derivatives settled, net (Note 10) (18,040) (729)
Deferred tax expense 12,380
 22,084
Gain on disposition of assets (575) (1,153)
Cash proceeds (payments) on derivatives settled, net (Note 10)Cash proceeds (payments) on derivatives settled, net (Note 10)5,314 (8,928)
Deferred tax (benefit) expenseDeferred tax (benefit) expense(2,318)5,636 
(Gain) loss on disposition of assets(Gain) loss on disposition of assets1,193 (322)
Stock compensation plans 17,397
 12,478
Stock compensation plans11,187 12,073 
Contract assets and liabilities, net (Note 2) (3,671) —
Contract assets and liabilities, net (Note 2)(1,283)(2,371)
Other, net 2,835
 1,397
Other, net1,117 1,998 
Changes in operating assets and liabilities increasing (decreasing) cash:    Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable (15,558) (36,381)Accounts receivable26,939 (1,865)
Accounts payable (14,867) 4,873
Accounts payable(30,374)(403)
Material and supplies —
 17
Material and supplies(43)4 
Income taxes —
 (15)
Accrued liabilities 16,242
 20,280
Accrued liabilities(1,245)1,572 
Other, net (2,975) 1,106
Other, net(1,225)(1,526)
Net cash provided by operating activities 236,535
 184,792
Net cash provided by operating activities127,501 159,640 
INVESTING ACTIVITIES:    INVESTING ACTIVITIES:
Capital expenditures (304,054) (167,392)Capital expenditures(246,638)(189,916)
Producing properties and other acquisitions (769) (55,429)Producing properties and other acquisitions(3,313)(962)
Proceeds from disposition of assets 25,316
 20,137
Proceeds from disposition of assets7,340 23,528 
Other —
 (1,500)
Net cash used in investing activities (279,507) (204,184)Net cash used in investing activities(242,611)(167,350)
FINANCING ACTIVITIES:    FINANCING ACTIVITIES:
Borrowings under credit agreement 71,200
 251,401
Borrowings under credit agreement271,200 71,200 
Payments under credit agreement (249,200) (250,100)Payments under credit agreement(160,200)(249,200)
Payments on capitalized leases (2,869) (2,967)
Proceeds from common stock issued, net of issue costs (Note 14) —
 18,623
Proceeds from investments of non-controlling interest 300,000
 —
Payments on finance leasesPayments on finance leases(1,980)(1,901)
Proceeds from investments in non-controlling interestProceeds from investments in non-controlling interest— 300,000 
Employee taxes paid by withholding sharesEmployee taxes paid by withholding shares(4,073)(4,947)
Transaction costs associated with sale of non-controlling interest (2,303) —
Transaction costs associated with sale of non-controlling interest— (2,254)
Distributions to non-controlling interestDistributions to non-controlling interest(918)— 
Book overdrafts 17,000
 2,364
Book overdrafts5,298 (1,581)
Net cash provided by financing activities 133,828
 19,321
Net cash provided by financing activities109,327 111,317 
Net increase (decrease) in cash and cash equivalents 90,856
 (71)Net increase (decrease) in cash and cash equivalents(5,783)103,607 
Cash and cash equivalents, beginning of period 701
 893
Cash and cash equivalents, beginning of period6,452 701 
Cash and cash equivalents, end of period $91,557
 $822
Cash and cash equivalents, end of period$669 $104,308 


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






9
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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - CONTINUED


Six Months Ended
 June 30,
 2019 2018
 (In thousands)
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)$15,748 $18,246 
Income taxes— — 
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment(6,260)(3,747)
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations(2,057)7,854 
  Nine Months Ended
  September 30,
  2018 2017
  (In thousands)
Supplemental disclosure of cash flow information:    
Cash paid during the year for:    
Interest paid (net of capitalized) 14,418
 14,601
Income taxes 3,600
 —
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment (28,770) (20,122)
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations 8,546
 (3,203)


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

10
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1 – BASIS OF PREPARATION AND PRESENTATION


The unaudited condensed consolidated financial statements in this report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires. We consolidate the activities of Superior Pipeline Company, L.L.C. (Superior), a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, which qualifies as a VIEVariable Interest Entity (VIE) under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power through our 50% ownership, to direct those activities that most significantly affect the economic performance of Superior as further described in Note 1314 – Variable Interest Entity Arrangements.


The condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This report should be read with the audited consolidated financial statements and notes in our Form 10-K, filed February 27, 2018,26, 2019, for the year ended December 31, 2017 as amended by our Form 10-K/A filed on August 6, 2018.


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


•Balance Sheets at SeptemberJune 30, 20182019 and December 31, 2017;2018;
Income •Statements of Operations for the three and ninesix months ended SeptemberJune 30, 20182019 and 2017;
2018;
•Statements of Comprehensive Income (Loss) for the three and ninesix months ended SeptemberJune 30, 20182019 and 2017;
2018;
•Statements of Changes in Shareholders' Equity for the ninethree and six months ended SeptemberJune 30, 20182019 and 2017;2018; and
•Statements of Cash Flows for the ninesix months ended SeptemberJune 30, 20182019 and 2017.
2018.


Our financial statements are prepared in conformity with GAAP, which requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and notes. Actual results may differ from those estimates. Results for the ninesix months ended SeptemberJune 30, 20182019 and 20172018 are not necessarily indicative of the results we may realize for the full year of 2018,2019, or that we realized for the full year of 2017.2018.


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

Accounting Changes - Recent Accounting Pronouncements - Adopted


As of January 1, 2018,2019, we adopted ASU 2018-02 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This standard is explained further in Note 8Leases - New Accounting Pronouncements. We adopted this amendment earlyTopic 842 (ASC 842) using the modified retrospective method and it had no material effectthe optional transition method to our financial statements. We previously used 37.75%record the adoption impact through a cumulative adjustment to calculate the tax effect on AOCI and we now use 24.5%. This change is reflected in our Unaudited Condensed Consolidated Statements of Comprehensive Income and in Note 14 - Equity.

Also, as ofequity. Results for reporting periods beginning after January 1, 2018, we adopted ASU 2014-09 Revenue from Contracts with Customers -2019, are presented under Topic 606 (ASC 606)842, while prior periods are not adjusted and all later amendments that modified ASC 606.continue to be reported under the accounting standards in effect for those periods. This new revenuelease standard is explained further in Note 8 – New Accounting Pronouncements. We elected to apply this standard on the modified retrospective approach method to contracts not completed as of January 1, 2018, where the cumulative effect on adoption, which only affected our mid-stream segment, is recognized as an adjustment to opening retained earnings at January 1, 2018. This adjustment related to the timing of revenue recognition for certain demand fees. Our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative prior periods have not been adjusted and continue to be reported under ASC 605.


The additional disclosures required by the ASU areASC 842 have been included in Note 212 – Revenue from Contracts with Customers.Leases.


NOTE 2 – REVENUE FROM CONTRACTS WITH CUSTOMERS


Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is how we disaggregate our disaggregation of revenue and how we report our segment revenue is reported (as reflected in Note 1516 – Industry Segment Information). Revenue from the oil and natural gas segment is derived from sales of our oil and natural gas production. Revenue from the contract drilling segment is derived bycomes from contracting with upstream companies to drill an agreed-on number of wells or provide

drilling rigs and services over an agreed-on time period. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas production and NGLs and selling those commodities. We sell the hydrocarbons (from theour oil and natural gas and mid-stream segments) to other mid-stream and downstream oil and gas companies.


We satisfy the performance obligation under each segment's contracts as follows: for the contract drilling and mid-stream contracts, we satisfy the performance obligation over the agreed-on time within the contracts, and for oil and natural gas contracts, we satisfy the performance obligation with each delivery
11
Table of volumes. For oil and natural gas contracts, as it is more feasible, we account for these deliveries monthly. Per the contracts for all segments, customers pay for the services/goods received monthly within an agreed on number of days following the end of the month. Besides the mid-stream demand fees discussed further below, there were no other contract assets or liabilities falling within the scope of this accounting pronouncement.Contents

Oil and Natural Gas Contracts, Revenues Implementation Impact to Retained Earnings, and Performance Obligations

Typical types of revenue contracts signed by our segments are Oil Sales Contracts, Gas Purchase Agreements, 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 our Joint Operating Agreements. Contract term can range from a single month to a term spanning a decade or more; some may also include evergreen provisions. Revenues from sales we make are recognized when our customer obtains control of the sold product. For sales to other mid-stream and downstream oil and gas companies, this would occur at a point in time, typically on delivery to the customer. Sales generated from our non-operated interest are recorded based on the information obtained from the operator. Our adoption of this standard required no adjustment to opening retained earnings.


Certain costs—as either a deduction from revenue or as an expense—isare determined based on when control of the commodity is transferred to our customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing, and transportation costs included as part of the contract price with the customer on transfer of control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity represent operating costs. The impact of the adoption of ASC 606 did not impact income from operations or net income for the three or nine months ended September 30, 2018. These tables summarize the impact of the adoption of ASC 606 on revenue and operating costs for the three and nine months ended September 30, 2018, respectively:

  Three Months Ended September 30, 2018
  As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606
  (In thousands)
Oil and natural gas revenues $111,623
 $(5,200) $116,823
Oil and natural gas operating costs 32,139
 (5,200) 37,339
Gross profit $79,484
 $—
 $79,484
  Nine Months Ended September 30, 2018
  As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606
  (In thousands)
Oil and natural gas revenues $317,040
 $(12,102) $329,142
Oil and natural gas operating costs 100,519
 (12,102) 112,621
Gross profit $216,521
 $—
 $216,521

Our performance obligation for all commodity contracts is the delivery of oil and gas volumes to the customer. Typically, the contract is for a specified period (for example, a month or a year); however, each delivery under that contract can be considered separately identifiable since each delivery provides benefits to the customer on its own. For feasibility, as accounting for a monthly performance obligation is not materially different than identifying a more granular performance obligation, we conclude this performance obligation is satisfied monthly. We typically receive a payment within a set number of days following the end of the month which includes payment for all deliveries in that month. Depending on contract circumstances, judgment could be required to determine when the transfer of control occurs. Generally, depending of the facts

and circumstances, we consider the transfer of control of the asset in a commodity sale to occur at the point the commodity transfers to our purchaser.

Most of the consideration received by us for oil and gas sales is variable. Most of our contracts state the consideration is calculated by multiplying a variable quantity by an agreed-on index price less deductions related to gathering, transportation, fractionation, and related fuel charges. There are also instances where the consideration is quantity multiplied by a weighted average sales price. These different pricing tools can change the perception of when control transfers; however, when analyzed with other control factors, typically the accounting conclusion is the same for both pricing methods. In these instances, the variable consideration is partially constrained. In addition, all variable consideration is settled at the end of the month; therefore, whether the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known prior to each reporting period. An estimation and allocation of transaction price and future obligations are not required.

Contract Drilling Contracts, Revenues, Implementation impact to retained earnings, and Performance Obligations


The contracts our drilling segment uses are primarily industry standard IADC contracts model year 2003 and 2013. Contract terms range from six months to three or more years or can be based on terms to drill a specific number of wells. The allocation rules in ASC 606 (called the "series guidance") provide that a contract may contain a single performance obligation composed of a series of distinct goods or services if 1) each distinct good or service is substantially the same and would meet the criteria to be a performance obligation satisfied over time and 2) each distinct good or service is measured using the same method as it relates to the satisfaction of the overall performance obligation. We have determined that the delivery of drilling services is within the scope of the series guidance as both criteria noted above are met. Specifically, 1) each distinct increment of service (i.e. hour available to drill) that the drilling contractor promises to transfer represents a performance obligation that would meet the criteria for recognizing revenue over time, and 2) the drilling contractor would use the same method for measuring progress toward satisfaction of the performance obligation for each distinct increment of service in the series. At inception, the total transaction price will be estimated to include any applicable fixed consideration, unconstrained variable consideration (estimated day rate mobilization and demobilization revenue, estimated operating day rate revenue to be earned over the contract term, expected bonuses (if material and can be reasonably estimated without significant reversal), and penalties (if material and can be reasonably estimated without significant reversal)). Allocation rules under this new standard allow us to recognize revenues associated with our drilling contacts in materially the same manner as under the previous revenue accounting standard. A contract liability will be recorded for consideration received before the corresponding transfer of services. Those liabilities will generally only arise in relation to upfront mobilization fees paid in advance and are allocated/recognized over the entire performance obligation. Such balances will be amortized over the recognition period based on the same method of measure used for revenue. On adoption of the standard, no adjustment to opening retained earnings was required.

Our performance obligation for all drilling contracts is to drill the agreed-on number of wells or drill over an agreed-on period as stated in the contract. Any mobilization and demobilization activities are not considered distinct within the context of the contract and therefore, any associated revenue is allocated to the overall performance obligation of drilling services and recognized ratably over the initial term of the related drilling contract. It typically takes from 10 to 90 days to complete drilling a well; therefore, depending on the number of wells under a contract, the contract term could be up to three years. Most of the drilling contracts are for less than one year. As the customer simultaneously receives and consumes the benefits provided by the company’s performance, and the company’s performance enhances an asset that the customer controls, the performance obligation to drill the well occurs over time. We typically receive payment within a set number of days following the end of the month and that payment includes payment for all services performed during that month (calculated on an hourly basis). The company satisfies its overall performance obligation when the well included in the contract is drilled to an agreed-on depth or by a set date.

All consideration received for contract drilling is variable, excluding termination fees, which we have concluded will not apply to our contracts as of the reporting date. The consideration is calculated by multiplying a variable quantity (number of days/hours) by an agreed-on daily price (for the daily rate, mobilization and demobilization revenue). Other revenue items under the contract may include bonus/penalty revenue, reimbursable revenue, drilling fluid rates, and early termination fees. All variable consideration is not constrained but is settled at the end of the month; therefore, whether the variability is constrained or not does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period excluding certain bonuses/penalties which might be based on activity that occurs over the entire term of the contract. We have evaluated the mobilization and de-mobilization charges ondue under our outstanding contracts, however, thedrilling contracts. The impact of those charges to the financial statements was immaterial. As of SeptemberJune 30, 2018,2019, we had 3424 contract drilling contracts (21 of which are long-term) for a duration of two monthswith terms ranging from one month to almost three years.



Under the guidance in relation to disclosures regarding the remaining performance obligations, there is a practical expedient for contracts with an original expected duration of one year or less (ASC 606-10-50-14) and for contracts where the entity can recognize revenue as invoiced (ASC 606-10-55-18). The majorityMost of our drilling contracts have an original term of less than one year; however, theyear. The remaining performance obligations under the contracts that have a longer duration are not material.


Mid-stream Contracts Revenues and Implementation impact to retained earnings, and Performance Obligations


Revenues are generated from the fees earned for gas gathering and processing services provided to a customer. The typical revenue contracts used by this segment are gas gathering and processing agreements. Contract terms range from a single month to terms spanning a decade or more, some include evergreen provisions. Fees forThe following tables show the changes in our mid-stream services (gathering, transportation, processing)contract asset and contract liability balances during the six months ended June 30, 2019:

Contract AssetsAmount
(In thousands)
Balance at December 31, 2018 (1)
$13,164 
Amounts invoiced in excess of revenue recognized(86)
Balance at June 30, 2019 (1)
$13,078 
_______________________
1.At December 31, 2018, total contract assets are performance obligationsincluded in prepaid expenses and meet the criteriaother and other assets of over time recognition which could be considered a series$0.3 million and $12.9 million, respectively, in our Consolidated Balance Sheet. At June 30, 2019, total contract assets included prepaid expenses and other and other assets of distinct performance obligations that represents one overall performance obligation of gas gathering$3.4 million and processing services.

On adoption of the standard, an adjustment to opening retained earnings was made for $1.7$9.7 million, ($1.3 million, net of tax). This adjustment—related to the timing of revenue recognized on certain demand fees—impactedrespectively, in our Unaudited Condensed Consolidated Balance Sheet (for the periods indicated) as follows:Sheet.

  Balance at December 31, 2017 Adjustments due to ASC 606 
Balance at January 1,
 2018
  (In thousands)
Assets:      
Other assets $16,230
 $10,798
 $27,028
Liabilities and shareholders' equity:      
Current portion of other long-term liabilities 13,002
 2,748
 15,750
Other long-term liabilities 100,203
 9,737
 109,940
Deferred income taxes 133,477
 (413) 133,064
Retained earnings 799,402
 (1,274) 798,128
Contract LiabilitiesAmount
(In thousands)
Balance at December 31, 2018 (1)
$9,882 
New contract60 
Revenue included in beginning balance(1,429)
Balance at June 30, 2019 (1)
$8,513 


______________________
1.At SeptemberDecember 31, 2018, total contract liabilities are included in current portion of other long-term liabilities and other long-term liabilities of $2.9 million and $7.0 million, respectively, in our Consolidated Balance Sheet. At June 30, 2018:
  As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606
  (In thousands)
Assets:      
Prepaid expenses and other $9,419
 $206
 $9,213
Other assets 28,703
 12,383
 16,320
Liabilities and shareholders' equity:      
Current portion of other long-term liabilities 14,150
 2,874
 11,276
Other long-term liabilities 101,410
 7,731
 93,679
Deferred income taxes 164,964
 486
 164,478
Retained earnings 830,680
 1,498
 829,182


For the three months ended September 30, 2018:
  As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606
  (In thousands)
Gas gathering and processing revenues $57,823
 $1,300
 $56,523
Deferred income tax expense 6,744
 318
 6,426
Net income 21,123
 982
 20,141

This adjustment related to the timing2019, total contract liabilities included current portion of revenue recognized on certain demand feesother long-term liabilities and had the following impact to the Unauditedother long-term liabilities of $2.9 million and $5.6 million, respectively, in our Condensed Consolidated Income Statement for the nine months ended September 30, 2018:Balance Sheet.
  As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606
  (In thousands)
Gas gathering and processing revenues $167,926
 $3,671
 $164,255
Deferred income tax expense 12,380
 899
 11,481
Net income 37,138
 2,772
 34,366

The only fixed consideration related to mid-stream consideration is a demand fee calculated by multiplying an agreed-on price by a fixed number of volumes per month over a specified term in the contract.


Included below is the additional fixed revenue we will earn over the remaining term of the contracts and excludes all variable consideration to be earned with the associated contract.
ContractRemaining Term of ContractJuly - December 201920202021 2022 2023 and Beyond Total Remaining Impact to Revenue 
(In thousands) 
Demand fee contracts3-9 years$1,295 $(3,775)$(3,501)$1,380 $36 $(4,565)

ContractRemaining Term of ContractOctober - December 20182019202020212022Total Remaining Impact to Revenue
  (In thousands) 
Demand fee contracts4-5 years$1,299
$2,632
$(3,781)$(3,507)$1,374
$(1,983)

Before implementing ASC 606, we immediately recognized the entire demand fee since the fee was payable within the first five years from the effective date of the contract and not over the entire term of the contract. However, as the demand fee does not specifically relate to a distinct performance obligation, under the new standard that amount should now be recognized over the life of the contract. Therefore, the demand fee previously recognized for $1.7 million ($1.3 million, net of tax) was adjusted to retained earnings as of January 1, 2018 and will be recognized over the remaining term of the contract. As this amount is fixed, recognition of the remaining portion will be stable. Besides the demand fee, there were no other contract assets or liabilities (see above for the balance sheet line items where they are reported). For the three and nine months ended September 30, 2018, $1.3 million and $3.7 million, respectively, was recognized in revenue for these demand fees.
12
  September 30,
2018		 January 1,
2018		 Change
  (In thousands)
Contract assets $12,589
 $10,798
 $1,791
Contract liabilities 10,605
 12,485
 (1,880)
Contract assets (liabilities), net $1,984
 $(1,687) $3,671

Our performance obligations for all contracts is to gather, transport, or process an agreed-on numberTable of volumes as stated in the contract. Typically, the contract will establish a period over which the company will perform the mid-stream services. Certain contracts also include an agreed-on quantity (or an agreed-on minimum quantity) of volumes that the company will deliver or service. The term under mid-stream service contracts is typically five to ten years. Under service contracts, as the customer simultaneously receives and consumes the benefits provided by the entity’s performance as the entity performs, the performance obligation to gather, transport, or process occurs over time. We typically receive payment within a set number ofContents

days following the end of the month and includes payment for all services performed that month. Our overall performance obligation is satisfied at the end of the contract term.

Most of the consideration received under mid-stream service contracts is variable. The consideration is calculated by multiplying a variable quantity (number of volumes) by an agreed-on price per MCF (commodity fee and the gathering fee). One fixed component of revenue is calculated by multiplying an agreed-on price by a certain volume commitment (MCF per day). Other revenue items may include shortfall fees. All variable consideration is settled at the end of the month; therefore, whether or not the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period. However, this excludes the shortfall fee as this fee could be based on a set number of volumes over the course of more than one month.

Per the new guidance related to disclosures for remaining performance obligations, there is a practical expedient for contracts with an original expected duration of one year or less (ASC 606-10-50-14). There is also a practical expedient for “variable consideration [that] is allocated entirely to a wholly unsatisfied performance obligation… that forms part of a single performance obligation… for which the criteria in paragraph 606-10-32-40 have been met” (ASC 606-10-50-14A). As stated previously, the contract term for mid-stream services is typically longer than one year. However, based on the guidance at 606-10-32-40, we determined some of the variable payment in mid-stream service agreements specifically relates to the entity’s efforts to satisfy the performance obligation and that “allocating the variable amount entirely to the distinct good or service is consistent with the allocation objective in paragraph 606-10-32-28.” Therefore, the practical expedient relates to this variable consideration: the commodity fee and the gathering fee. The last time we received a shortfall fee was in 2016 and the amount was immaterial to total mid-stream revenues. These terms have historically been limited in our contracts.

We calculate revenue earned from the variable consideration related to mid-stream services by multiplying the number of volumes serviced times an agreed-on price. Therefore, the variable portion of this consideration is due to the change in volumes. This variability is resolved at the end of each month as the company will know the number of volumes serviced under each contract and payment is received monthly. The mid-stream gathering service contracts remaining are for a duration of less than one year to 15 years.

While long term service contracts are in place as of the reporting date, due to the variable volumes an estimation and allocation of transaction price and future obligations are not required.

NOTE 3 – DIVESTITURES
Divestitures


Oil and Natural Gas


We sold $2.1 million of non-core oil and natural gas assets, net of related expenses, for $22.3during the first six months of 2019, compared to $22.4 million during the first ninesix months of 2018, compared to $18.0 million during the first nine months of 2017. Proceeds from those sales2018. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.


Mid-StreamContract Drilling


On April 3,In December 2018, we sold 50%removed 41 drilling rigs and other equipment from service. We estimated the fair value of the ownership interest in our mid-stream segment, Superior. The purchaser is SP Investor Holdings, LLC,41 drilling rigs based on the estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these estimates, we recorded a holding company jointly owned by OPTrustpre-tax non-cash write-down of approximately $147.9 million. During the first six months of 2019, we sold three of these drilling rigs and funds managed and/or advised by Partners Group, a global private markets investment manager. We received $300.0 million because of this sale. A portionsome of the other equipment to unaffiliated third parties. The proceeds were usedof those sales, less costs to pay down our bank debtsell, was less than the applicable $3.0 million net book value resulting in a loss of $0.2 million. The remaining drilling rigs and the remainder will accelerate the drilling program of our upstream subsidiary, Unit Petroleum Company, make additional capital investments in the jointly owned Superior, and for general working capital purposes. In connection with the sale of the interest in Superior, we took the necessary actions under the Indenture governing our outstanding senior subordinated notes to secure the ability to close the sale and have Superior released from the Indenture.

Superiorequipment will be governedmarketed for sale throughout 2019 and managed under its Amended and Restated Limited Liability Company Agreement and the Master Services and Operating Agreement (MSA) signed by Superior and an affiliateremain classified as assets held for sale. The net book value of Unit, as both agreements may be amended occasionally. Further details are in Note 13 – Variable Interest Entity Arrangements.those assets is $19.5 million.



NOTE 4 – EARNINGS (LOSS) PER SHARE


Information related to the calculation of earnings (loss) per share attributable to Unit Corporation is as follows:
Earnings (Loss)
(Numerator)		Weighted
Shares
(Denominator)		Per-Share
Amount
 (In thousands except per share amounts)
For the three months ended June 30, 2019
Basic loss attributable to Unit Corporation per common share$(8,509)52,930 $(0.16)
Effect of dilutive stock options and restricted stock— — — 
Diluted loss attributable to Unit Corporation per common share$(8,509)52,930 $(0.16)
For the three months ended June 30, 2018
Basic earnings attributable to Unit Corporation per common share$5,788 52,050 $0.11 
Effect of dilutive stock options and restricted stock— 731 — 
Diluted earnings attributable to Unit Corporation per common share$5,788 52,781 $0.11 
  
Earnings
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
  (In thousands except per share amounts)
For the three months ended September 30, 2018      
Basic earnings attributable to Unit Corporation per common share $18,899
 52,068
 $0.36
Effect of dilutive stock options and restricted stock —
 1,072
 —
Diluted earnings attributable to Unit Corporation per common share $18,899
 53,140
 $0.36
For the three months ended September 30, 2017      
Basic earnings attributable to Unit Corporation per common share $3,705
 51,386
 $0.07
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) —
 586
 —
Diluted earnings attributable to Unit Corporation per common share $3,705
 51,972
 $0.07


Because of the net loss for the three months ended June 30, 2019, approximately 283,000 weighted average shares related to stock options and restricted stock were antidilutive and were excluded from the earnings per share calculation above.

The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
Three Months Ended
 June 30,
 2019 2018 
Stock options42,000 66,500 
Average exercise price$48.56 $44.42 


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  Three Months Ended
  September 30,
  2018 2017
Stock options and SARs 66,500
 178,755
Average exercise price $44.42
 $47.75
Earnings (Loss) (Numerator)Weighted Shares (Denominator)Per-Share Amount
(In thousands except per share amounts)
For the six months ended June 30, 2019
Basic loss attributable to Unit Corporation per common share$(12,013)52,744 $(0.23)
Effect of dilutive stock options and restricted stock— — — 
Diluted loss attributable to Unit Corporation per common share$(12,013)52,744 $(0.23)
For the six months ended June 30, 2018
Basic earnings attributable to Unit Corporation per common share$13,653 51,891 $0.26 
Effect of dilutive stock options and restricted stock— 651 — 
Diluted earnings attributable to Unit Corporation per common share$13,653 52,542 $0.26 

Because of the net loss for the six months ended June 30, 2019, approximately 286,000 weighted average shares related to stock options and restricted stock were antidilutive and were excluded from the earnings per share calculation above.
  Earnings (Loss)
(Numerator)		 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
  (In thousands except per share amounts)
For the nine months ended September 30, 2018      
Basic earnings attributable to Unit Corporation per common share $32,552
 51,951
 $0.63
Effect of dilutive stock options and restricted stock —
 808
 (0.01)
Diluted earnings attributable to Unit Corporation per common share $32,552
 52,759
 $0.62
For the nine months ended September 30, 2017      
Basic earnings attributable to Unit Corporation per common share $28,693
 51,019
 $0.56
Effect of dilutive stock options, restricted stock, and SARs —
 550
 —
Diluted earnings attributable to Unit Corporation per common share $28,693
 51,569
 $0.56


The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
Six Months Ended
 June 30,
 2019 2018 
Stock options42,000 66,500 
Average exercise price$48.56 $44.42 

  Nine Months Ended
  September 30,
  2018 2017
Stock options and SARs 66,500
 178,755
Average exercise price $44.42
 $47.75


NOTE 5 – ACCRUED LIABILITIES


Accrued liabilities consisted of:
June 30,
2019		December 31,
2018
 (In thousands)
Employee costs$13,910 $22,056 
Lease operating expenses10,552 12,756 
Interest payable6,741 6,635 
Taxes6,675 1,378 
Third-party credits2,824 2,129 
Other4,473 4,710 
Total accrued liabilities$45,175 $49,664 
  September 30,
2018		 December 31,
2017
  (In thousands)
Employee costs $17,880
 $19,521
Interest payable 17,446
 6,745
Lease operating expenses 11,474
 11,819
Taxes 10,317
 3,404
Derivative settlements 3,383
 —
Third-party credits 2,099
 2,240
Other 5,144
 4,794
Total accrued liabilities $67,743
 $48,523
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NOTE 6 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES


Long-Term Debt


OurAs of the date indicated, our long-term debt as of the dates indicated consisted of the following:
June 30,
2019		December 31,
2018
 (In thousands)
Unit credit agreement with an average interest rate of 4.2% at June 30, 2019$103,500 $— 
Superior credit agreement with an average interest rate of 6.5% at June 30, 20197,500 — 
6.625% senior subordinated notes due 2021650,000 650,000 
Total principal amount761,000 650,000 
Less: unamortized discount(1,303)(1,623)
Less: debt issuance costs, net(3,107)(3,902)
Total long-term debt$756,590 $644,475 
  September 30,
2018		 December 31,
2017
  (In thousands)
Unit credit agreement with an average interest rate of 3.4% at December 31, 2017 $—
 $178,000
Superior credit agreement —
 —
6.625% senior subordinated notes due 2021 650,000
 650,000
Total principal amount 650,000
 828,000
Less: unamortized discount (1,780) (2,234)
Less: debt issuance costs, net (4,299) (5,490)
Total long-term debt $643,921
 $820,276


Unit Credit Agreement. On October 18, 2018, we signed a Fifth Amendment to our Our Senior Credit Agreement (Unit credit agreement) originallyis scheduled to mature on April 10, 2020. The details of this amendment are discussed in Note 17 – Subsequent Events and have not been incorporated intoOctober 18, 2023. Under that agreement, the discussionamount we can borrow is the lesser of the Unit credit agreement immediately below.

On April 2, 2018,amount we entered into a fourth amendmentelect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to the Unit credit agreement (Fourth Amendment). The Fourth Amendment provided, among other things, for a reduction ofexceed the maximum credit agreement amount from $875.0 million toof $1.0 billion. Our elected commitment amount is $425.0 million, a reduction in themillion. Our borrowing base from $475.0 million tois $425.0 million,million. We are currently charged a reduction incommitment fee of 0.375% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the total commitment amount from $475.0borrowing base. Total fees of $3.3 million to $425.0 million;in origination, agency, syndication, and other related fees are being amortized over the full releaselife of Superior and its subsidiaries as a borrower and co-obligor under the Unit credit agreement. Under the amendment, once the saleagreement, we have pledged as collateral 80% of the interest in Superior was completed, we had to use partproved developed producing (discounted as present worth at 8%) total value of the proceeds to pay down the Unit credit agreement. The Superior sale closed on April 3, 2018our oil and the pay down was made that day.gas properties.


On May 2, 2018, the company signedwe entered into a Pledge Agreement with BOKF, NA (dba Bank of Oklahoma), as administrative agent to benefit the secured parties, under which we grantedgranting a security interest in the limited liability membership interests and other equity interests we own in Superior (which as of this report is 50% of the aggregate outstanding equity interests of Superior) as additional collateral for our obligations under the Unit credit agreement.

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 previous origination, agency, syndication, and other related fees. We incurred no additional fees related to the fourth amendment. We are amortizing these fees over the life of the Unit credit agreement. Under the Unit credit agreement, we have pledged as collateral 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties.



The borrowing base amountamount–which is subject to redetermination by the lenders on April 1st and October 1st of each year and year–is based on a percentage of the discounted future value of our oil and natural gas reserves. 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 Unit credit agreement.


At our election, any part of the outstanding debt under the Unit credit agreement can be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base for the term plus 2.00%1.50% to 3.00%2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the Unit credit agreement but in no event less than LIBOR plus 1.00% plus a margin.margin. The credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index. Interest is payable at the end of each month or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty. At SeptemberJune 30, 2018,2019, we had no$103.5 million outstanding borrowings under the Unit credit agreement.


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


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The Unit 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;
•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; and
•investments in Unrestricted Subsidiaries (as defined in the Unit credit agreement) over $200.0 million.


Effective September 30, 2018, theThe Unit credit agreement also requires that we have at the end of each quarter:


•a current ratio (as defined in the credit agreement) of not less than 1 to 1.
•a leverage ratio of funded debt to consolidated EBITDA (as defined in the Unit credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.


As of SeptemberJune 30, 2018,2019, we were in compliance with the Unit credit agreementthese covenants.


Superior Credit Agreement. On May 10, 2018, Superior signed a five-year,five-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions (Superior credit agreement). The amounts borrowed under the Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) third day LIBOR plus 1.00%) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems. The credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index.


Superior is currently charged a commitment fee of 0.375% on the amount available but not borrowed which varies based on the amount borrowed as a percentage of the total borrowing base. Superior paid $1.7 million in origination, agency, syndication, and other related fees. These fees are being amortized over the life of the Superior credit agreement.


The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00,, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00.1.00. The Superior credit agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As of SeptemberJune 30, 2018,2019, Superior was in compliance with the Superior credit agreementthese covenants.
 
The borrowings under the Superior credit agreement will fund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior. As of June 30, 2019, we had $7.5 million outstanding borrowings under the Superior credit agreement.


On June 27, 2018, Superior and the lenders amended the Superior credit agreement to revise certain definitions in the agreement.


Superior's credit agreement is not guaranteed by Unit.


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


The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing
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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 significant 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. Effective April 3, 2018, Superior is no longer a Guarantor of the Notes. AnyExcluding Superior, any of our other 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, subjectunless the Company has exercised its right to certain conditions,redeem all of the Notes, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. As of May 15, 2019, we may redeem the Notes at a redemption price equal to 100% of the principal amount of the Notes plus accrued and unpaid interest on 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 SeptemberJune 30, 2018.2019.


We may from time to time seek to retire or purchase our outstanding Note debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Other Long-Term Liabilities


Other long-term liabilities consisted of the following:
June 30,
2019		December 31,
2018
 (In thousands)
Asset retirement obligation (ARO) liability$67,433 $64,208 
Workers’ compensation12,118 12,738 
Finance lease obligations9,400 11,380 
Contract liability8,513 9,881 
Separation benefit plans9,749 8,814 
Deferred compensation plan6,002 5,132 
Gas balancing liability3,372 3,331 
116,587 115,484 
Less current portion13,887 14,250 
Total other long-term liabilities$102,700 $101,234 
  September 30,
2018		 December 31,
2017
  (In thousands)
Asset retirement obligation (ARO) liability $62,727
 $69,444
Workers’ compensation 12,832
 13,340
Capital lease obligations 12,355
 15,224
Contract liability 10,605
 —
Separation benefit plans 8,135
 6,524
Deferred compensation plan 5,623
 5,390
Gas balancing liability 3,283
 3,283
  115,560
 113,205
Less current portion 14,150
 13,002
Total other long-term liabilities $101,410
 $100,203


Estimated annual principal payments under the terms of our long-term debt and other long-term liabilities during the five successive twelve-month periods beginning OctoberJuly 1, 20182019 (and through 2023)2024) are $14.1$13.9 million, $43.1$697.5 million, $659.8$5.6 million, $4.6$10.7 million, and $2.3$105.8 million, respectively.



Capital Leases

In 2014, Superior 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 $4.0 million current portion of the capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $8.4 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 2018. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $4.6 million and $0.8 million, respectively, at September 30, 2018. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, Superior has the option to purchase the assets at 10% of their then fair market value.

Future payments required under the capital leases at September 30, 2018 are:
  Amount
Beginning October 1, (In thousands)
2018 $6,195
2019 6,195
2020 5,322
Total future payments 17,712
Less payments related to:  
Maintenance 4,601
Interest 756
Present value of future minimum payments $12,355

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.

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The following table shows certain information about our estimated AROs for the periods indicated:
Six Months Ended
 June 30,
 2019 2018 
 (In thousands)
ARO liability, January 1:$64,208 $69,444 
Accretion of discount1,168 1,248 
Liability incurred3,656 211 
Liability settled(2,316)(3,142)
Liability sold(1,632)(94)
Revision of estimates (1)
2,349 

(4,829)
ARO liability, June 30:67,433 62,838 
Less current portion1,784 1,451 
Total long-term ARO$65,649 $61,387 
  Nine Months Ended
  September 30,
  2018 2017
  (In thousands)
ARO liability, January 1: $69,444
 $70,170
Accretion of discount 1,829
 2,112
Liability incurred 244
 1,123
Liability settled (3,907) (1,350)
Liability sold (105) (1,563)
Revision of estimates (1)
 (4,778)
4,993
ARO liability, September 30: 62,727
 75,485
Less current portion 1,451
 2,947
Total long-term ARO $61,276
 $72,538
_______________________ 
(1)Plugging liability estimates were revised in both 2018 and 2017 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

1.Plugging liability estimates were revised in both 2019 and 2018 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS


Measurement of Credit Losses on Financial Instruments (Topic 326). The FASB issued ASU 2016-13 which replaces current methods for evaluating impairment of financial instruments not measured at fair value, including trade accounts receivable and certain debt securities, with a current expected credit loss model. The amendment will be effective for reporting periods after December 15, 2019. We are evaluating the impact this will have on our financial statements by reviewing our accounts receivable accounts and our historic credit losses.

Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were

removed or modified and other disclosures were added. The amendment will be effective for reporting periods beginning after December 15, 2019. Early adoption is permitted. Also it is permitted to early adopt any removed or modified disclosure and delay adoption of the additional disclosures until their effective date. This amendment will not have a material impact on our financial statements.


Compensation—Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting. The FASB issued ASU 2018-07, to improve financial reporting for nonemployee share-based payments. The amendment expands Topic 718, Compensation—Stock Compensation to include share-based payments issued to nonemployees for goods or services. The amendment will be effective for years beginning after December 15, 2019, and interim periods within those years. This amendment will not have a material impact on our financial statements.

Income Taxes - Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118. In March 2018, the FASB issued ASU 2018-05 which updates the FASB’s Accounting Standards Codification to reflect the guidance in SAB 118, which adds Section EE, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” to SAB Topic 5, “Miscellaneous Accounting.” SAB 118 also provides guidance on applying ASC 740, Income Taxes, if the accounting for certain income tax effects of the Tax Cuts and Jobs Act of 2017 is incomplete when the financial statements are issued for a reporting period.

Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This amendment will not have a material impact on our financial statements.


Leases. Adopted Standards

Compensation—Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting. The FASB has issued several accounting standards updates and amendments relatedASU 2018-07, to leases in the past two years, which are codified withinimprove financial reporting for nonemployee share-based payments. The amendment expands Topic 842. For public companies, these are718, Compensation—Stock Compensation to include share-based payments issued to nonemployees for goods or services. The amendment is effective for annual periodsyears beginning after December 15, 2018, and interim periods within those annual periods. The standard requires lessees to recognize at the commencement date of a lease a lease liability, which represents the lessee's obligation to make lease payments arising from the lease, measured on a discounted basis; and a right-of-use asset, which represents the lessee's right to use a specified asset for the lease term. Other recently issued amendments to Topic 842years. This amendment did not have provided clarifying guidance regarding land easements, an additional modified retrospective transition method, and added several practical expedients to apply Topic 842 for both lessees and lessors. The standard will not apply to leases of mineral rights.

We have an implementation team working through the provisions of the new guidance including a review of different types of contracts to document our lease portfolio and assess the impact on our accounting, disclosures, processes, internal control over financial reporting, and the election of certain practical expedients. Our evaluation of the impact of the new guidance on our financial statements is on-going.statements.


We have made certain accounting policy decisions including that we plan to adopt the short-term lease recognition exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization threshold. Our transition will utilizeadopted ASC 842 on January 1, 2019, using the modified retrospective approach to adopting the new standard, and will be applied at the beginning of the period adopted (January 1, 2019) in accordance with ASU 2018-11. We expect to elect the transition practical expedient, which allows us to not evaluate land easements that existed prior to January 1, 2019,method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. We expectResults for certain lessee asset classes to elect the practical expedient and not separate lease and nonlease components. For these asset classes, we will account for the agreements as a single lease component.

We expect for certain lessor asset classes to elect the practical expedient and not separate lease and nonlease components and determine the appropriate accounting based on the predominate component of the contract. The assessment of predominance is ongoing.

We anticipate a material impact to the balance sheet across segments as we recognize Right of Use assets and liabilities but no material impact to the income statement (from the lessee's perspective). The assessment of the dollar value impact of adoption is on-going.

Adopted Standards

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The FASB issued ASU 2018-02, an amendment which provides financial statement preparers with an option to reclassify stranded tax effects within AOCI to retained earnings caused by the Tax Cuts and Jobs Act of 2017. The amendment is effective for fiscal yearsreporting periods beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. Organizations should apply the

proposed amendments either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Cuts and Jobs Act is recognized. We adopted this amendment early and it had no material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and now we are using 24.5%. The change is reflected in our Unaudited Condensed Consolidated Statements of Comprehensive Income and in Note 14 - Equity.

Revenue from Contracts with Customers. Effective January 1, 2018, we adopted ASC 606. This new revenue standard provides for a five-step analysis of transactions to determine when and how revenue is to be recognized. The guidance in this update supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. Under the standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all our revenue streams in the scope of ASC 606 and elected the modified retrospective approach method. Under that approach the cumulative effect on adoption is recognized as an adjustment to opening retained earnings at January 1, 2018. Only our mid-stream segment was affected. This adjustment related to the timing of revenue on certain demand fees. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative2019, are presented under Topic 842, while prior periods haveare not been adjusted and continue to be reported under ASC 605.the accounting standards in effect for those periods.


The additional disclosures required by ASC 606842 have been included in Note 212 – Revenue from Contracts with Customers.Leases.


Our internal control framework did not materially change because

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Table of this standard, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard, we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.Contents

NOTE 9 – STOCK-BASED COMPENSATION


For restricted stock awards and stock options, we had:
Three Months EndedSix Months Ended
June 30,June 30,
2019 2018 2019 2018 
(In millions)
Recognized stock compensation expense$4.7 $4.0 $8.5 $9.5 
Capitalized stock compensation cost for our oil and natural gas properties0.7 0.6 1.3 1.0 
Tax benefit on stock-based compensation1.2 1.0 2.1 2.3 
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2018 2017 2018 2017
  (In millions)
Recognized stock compensation expense $4.1
 $3.2
 $13.6
 $9.0
Capitalized stock compensation cost for our oil and natural gas properties 0.6
 0.5
 1.6
 1.3
Tax benefit on stock-based compensation 1.0
 1.2
 3.3
 3.4

The remaining unrecognized compensation cost related to unvested awards at SeptemberJune 30, 20182019 is approximately $19.0$24.8 million, of which $2.4$3.4 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is 1.00.8 of a 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) and to non-employee directors. 7,230,000 shares of the company's common stock are authorized for issuance to eligible participants under the amended plan with 2,000,000 shares being the maximum number of shares that can be issued as "incentive stock options."



We granted no SARs ordid not grant any stock options during either of the three or ninesix month periods ending SeptemberJune 30, 20182019 or 2017. We did not grant any restricted stock awards during either of the three month periods ending September 30, 2018 or 2017.2018. This table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated:
 Nine Months Ended Nine Months EndedThree Months EndedThree Months Ended
 September 30, 2018 September 30, 2017June 30, 2019June 30, 2018
 
Time
Vested
 Performance Vested 
Time
Vested
 Performance Vested Time
Vested		Performance VestedTime
Vested		Performance Vested
Shares granted:        Shares granted:
Employees 844,498
 362,070
 475,799
 173,373
Employees1,500 — 5,000 — 
Non-employee directors 44,312
 —
 49,104
 —
Non-employee directors72,784 — 44,312 — 
 888,810
 362,070
 524,903
 173,373
74,284 — 49,312 — 
Estimated fair value (in millions):(1)
        
Estimated fair value (in millions):(1)
Employees $16.2
 $7.3
 $11.8
 $4.5
Employees$— $— $0.1 $— 
Non-employee directors 0.9
 —
 0.9
 —
Non-employee directors0.9 — 0.9 — 
 $17.1
 $7.3
 $12.7
 $4.5
$0.9 $— $1.0 $— 
Percentage of shares granted expected to be distributed:        Percentage of shares granted expected to be distributed:
Employees 95% 74% 95% 91%Employees95 %N/A  95 %N/A  
Non-employee directors 100% N/A
 100% N/A
Non-employee directors100%  N/A  100 %N/A  
_______________________
(1)The performance shares represent 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

1.The performance shares represent 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)
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Six Months EndedSix Months Ended
June 30, 2019June 30, 2018
 Time
Vested		Performance VestedTime
Vested		Performance Vested
Shares granted:
Employees927,173 424,070 844,498 362,070 
Non-employee directors72,784 — 44,312 — 
999,957 424,070 888,810 362,070 
Estimated fair value (in millions):(1)
Employees$14.6 $7.1 $16.2 $7.3 
Non-employee directors0.9 — 0.9 — 
$15.5 $7.1 $17.1 $7.3 
Percentage of shares granted expected to be distributed:
Employees95 %54 %95 %74 %
Non-employee directors100 %N/A  100 %N/A  
_______________________
1.The performance shares represent 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

The time vested restricted stock awards granted during the first ninesix months of 20182019 and 20172018 are being recognized over a three-yearthree-year vesting period. During the first quarter of 20182019 and 2017,2018, two performance vested restricted stock awards were granted to certain executive officers. The first will cliff vest vests three years from the grant date based on the company's achievement of certain stock performance measures (TSR) at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest,vests, one-third each year, over a three-yearthree-year vesting period subject to the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected TSR performance criteria at SeptemberJune 30, 2018,2019, the participants are estimated to receive 49%7% of the 2018, 92%2019 and 63% of the 2017, and 170% of the 20162018 performance-based shares. The CFTA performance measurement at SeptemberJune 30, 20182019 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 20182019 awards for the first ninesix months of 20182019 was $7.5$4.0 million.


NOTE 10 – DERIVATIVES


Commodity Derivatives


We have signed various types of derivative transactions covering some of our projected natural gas and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of SeptemberJune 30, 2018,2019, these hedges made up our derivative transactions:


•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/Differential Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the commodity and pay or receive the published index price at the specified delivery point. We use basis/differential swaps to hedge the price risk between NYMEX and its physical delivery points.



•Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.

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


We have documented policies and procedures to monitor and control the use of derivative transactions. We do not engage in derivative transactions not otherwise tied to our projected production. Any changes in the fair value of our derivative transactions before maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Income Statements.Statements of Operations.


At SeptemberJune 30, 2018,2019, these derivatives were outstanding:
TermCommodityContracted Volume
Weighted Average 

Fixed Price
Contracted Market
Oct'18Jul'19 – Oct'19Natural gas – swap30,00060,000 MMBtu/day$3.0052.900 IF – NYMEX (HH)
Nov’18Nov'19 – Dec'18Dec'19Natural gas – swap20,00040,000 MMBtu/day$3.0132.900 IF – NYMEX (HH)
Jan'19Jul'19 – Dec'19Natural gas – swap10,000 MMBtu/day$2.810IF – NYMEX (HH)
Oct'18Natural gas – basis swap10,00020,000 MMBtu/day$(0.190)(0.659)NGPL TEXOKPEPL
Oct'18Jul'19 – Dec'18Dec'19Natural gas – basis swap10,000 MMBtu/day$(0.678)(0.625)PEPLNGL MIDCON
Oct'18Jul'19 – Dec'18Dec'19Natural gas – basis swap10,00030,000 MMBtu/day$(0.568)(0.265)NGPL MIDCONTEXOK
Nov’18Jan'20 – Dec'18Dec'20Natural gas – basis swap10,00030,000 MMBtu/day$(0.208)(0.275)NGPL TEXOK
Jul'19 – Dec'19Natural gas – collar20,000 MMBtu/day$2.63 - $3.03IF – NYMEX (HH)
Jan'19Jul'19 – Dec'19Natural gas – basis swap20,000 MMBtu/day$(0.659)PEPL
Jan'19 – Dec'19Natural gas – basis swap10,000 MMBtu/day$(0.625)NGL MIDCON
Jan'19 – Dec'19Natural gas – basis swap30,000 MMBtu/day$(0.265)NGPL TEXOK
Jan'20 – Dec'20Natural gas – basis swap30,000 MMBtu/day$(0.275)NGPL TEXOK
Oct'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Oct'18 – Dec'18Crude oil – swap4,000 Bbl/day$53.52WTI – NYMEX
Oct'18 – Dec'18Crude oil – price differential risk500 Bbl/day$7.00LLS/WTI
Oct'18 – Dec'18Crude oil – three-way collar2,000 Bbl/day$47.50 - $37.50 - $56.08WTI – NYMEX
Jan'19 – Dec'19Crude oil – three-way collar4,000 Bbl/day$61.25 - $51.25 - $72.93WTI – NYMEX

After September 30, 2018, the following derivatives were entered into:
TermCommodityContracted Volume
Weighted Average 
Fixed Price
Contracted Market
Jan'19 – Dec'19Natural gas – swap10,000 MMBtu/day$2.850IF – NYMEX (HH)
Jan'19 – Dec'19Natural gas – collar20,000 MMBtu/day$2.63 - $3.03IF – NYMEX (HH)
Jan'19 – Mar'19Natural gas – three-way collar10,000 MMBtu/day$3.00 - $2.75 - $4.35IF – NYMEX (HH)



The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
  Derivative Assets
  Fair Value
 Balance Sheet LocationJune 30,
2019		December 31,
2018
  (In thousands)
Commodity derivatives:
CurrentCurrent derivative asset$8,513 $12,870 
Long-termNon-current derivative asset— — 
Total derivative assets$8,513 $12,870 
    Derivative Assets
    Fair Value
  Balance Sheet Location September 30,
2018		 December 31,
2017
    (In thousands)
Commodity derivatives:      
Current Current derivative asset $—
 $721
Long-term Non-current derivative asset —
 —
Total derivative assets   $—
 $721

  Derivative Liabilities
  Fair Value
 Balance Sheet LocationJune 30,
2019		December 31,
2018
  (In thousands)
Commodity derivatives:
CurrentCurrent derivative liability$— $— 
Long-termNon-current derivative liability256 293 
Total derivative liabilities$256 $293 
    Derivative Liabilities
    Fair Value
  Balance Sheet Location September 30,
2018		 December 31,
2017
    (In thousands)
Commodity derivatives:      
Current Current derivative liability $13,067
 $7,763
Long-term Non-current derivative liability 1,542
 —
Total derivative liabilities   $14,609
 $7,763


All our counterparties are subject to master netting arrangements. If we have a legal right of set-off, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets.


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Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Income Statements for the three months ended September 30:of Operations at June 30:
Derivatives Instruments 
Location of Gain (Loss) Recognized in
Income on Derivative
 
Amount of Gain 
(Loss) Recognized in Income on Derivative
    2018 2017
    (In thousands)
Commodity derivatives 
Loss on derivatives (1)
 $(4,385) $(2,614)
Total   $(4,385) $(2,614)
_______________________
(1)Amounts settled during the 2018 and 2017 periods include net payments of $9.1 million and net proceeds of $0.8 million, respectively.

Three Months EndedSix Months Ended
June 30,June 30,
2019 2018 2019 2018 
 (In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $2,658, ($6,855), $5,314 and ($8,928), respectively$7,927 $(14,461)$995 $(21,223)
$7,927 $(14,461)$995 $(21,223)
Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Income Statements for the nine months ended September 30:
Derivatives Instruments 
Location of Gain (Loss) Recognized in
Income on Derivative
 Amount of Gain (Loss) Recognized in Income on Derivative
    2018 2017
    (In thousands)
Commodity derivatives 
Gain (loss) on derivatives (1)
 $(25,608) $21,019
Total   $(25,608) $21,019
_______________________
(1)Amounts settled during the 2018 and 2017 periods include net payments of $18.0 million and $0.7 million, respectively.


NOTE 11 – FAIR VALUE MEASUREMENTS


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


CostGross Unrealized GainsGross Unrealized LossesEstimated Fair Value
(In thousands)
Equity Securities:
June 30, 2019$830 $— $645 $185 
December 31, 2018$830 $— $636 $194 
  Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value
  (In thousands)
Equity Securities:  
September 30, 2018 $830
 $—
 $137
 $693
December 31, 2017 $830
 $102
 $—
 $932


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


Fair value is defined as the amount that would be received from the sale of an asset or paid for transferring a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows:


•Level 1—unadjusted quoted prices in active markets for identical assets and liabilities.


•Level 2—significant observable pricing inputs other than quoted prices included within level 1 either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.


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


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



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The following tables set forth our recurring fair value measurements:
 June 30, 2019
 Level 1Level 2Level 3Effect
of Netting		Net Amounts Presented
 (In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets$— $5,422 $3,945 $(854)$8,513 
Liabilities— (1,110)— 854 (256)
Total commodity derivatives— 4,312 3,945 — 8,257 
Equity securities185 — — — 185 
$185 $4,312 $3,945 $— $8,442 
  September 30, 2018
  Level 1 Level 2 Level 3 
Effect
of Netting
 Net Amounts Presented
  (In thousands)
Financial assets (liabilities):          
Commodity derivatives:          
Assets $—
 $1,282
 $88
 $(1,370) $—
Liabilities —
 (8,372) (7,607) 1,370
 (14,609)
Total commodity derivatives —
 (7,090) (7,519) —
 (14,609)
Equity securities 693
 —
 —
 —
 693
  $693
 $(7,090) $(7,519) $—
 $(13,916)

 December 31, 2018
 Level 1Level 2Level 3Effect
of Netting		Net Amounts Presented
 (In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets$— $3,225 $10,964 $(1,319)$12,870 
Liabilities— (1,278)(334)1,319 (293)
Total commodity derivatives— 1,947 10,630 — 12,577 
Equity securities194 — — — 194 
$194 $1,947 $10,630 $— $12,771 
  December 31, 2017
  Level 1 Level 2 Level 3 
Effect
of Netting
 Net Amounts Presented
  (In thousands)
Financial assets (liabilities):          
Commodity derivatives:          
Assets $—
 $2,137
 $3,344
 $(4,760) $721
Liabilities —
 (8,973) (3,550) 4,760
 (7,763)
Total commodity derivatives $—
 $(6,836) $(206) $—
 $(7,042)
Equity securities 932
 —
 —
 —
 932
  $932
 $(6,836) $(206) $—
 $(6,110)


All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties and no collateral has been posted as of SeptemberJune 30, 2018.2019.


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


Level 1 Fair Value Measurements


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


Level 2 Fair Value Measurements


Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index.


Level 3 Fair Value Measurements


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



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The following table is a reconciliation of our level 3 fair value measurements:
 Net Derivatives
Three Months EndedSix Months Ended
June 30,June 30,
 2019201820192018
 (In thousands)
Beginning of period$3,080 $(3,206)$10,630 $(206)
Total gains or losses (realized and unrealized):
Included in earnings (1)
2,060 (4,704)(3,374)(8,624)
Settlements(1,195)1,775 (3,311)2,695 
End of period$3,945 $(6,135)$3,945 $(6,135)
Total earnings (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period$865 $(2,929)$(6,685)$(5,929)
  Net Derivatives
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2018 2017 2018 2017
  (In thousands)
Beginning of period $(6,135) $4,093
 $(206) $(7,122)
Total gains or losses (realized and unrealized):        
Included in earnings (1)
 (3,700) (2,015) (12,324) 9,102
Settlements 2,316
 (592) 5,011
 (494)
End of period $(7,519) $1,486
 $(7,519) $1,486
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 $(1,384) $(2,607) $(7,313) $8,608
_______________________
_______________________
1.Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives.
(1)Commodity derivatives are reported in the Unaudited Condensed Consolidated Income Statements in gain (loss) on derivatives.


The following table provides quantitative information about our Level 3 unobservable inputs at SeptemberJune 30, 2018:2019:
Commodity (1)
 Fair Value Valuation Technique Unobservable Input Range
  (In thousands)      
Oil three-way collars $(7,607) Discounted cash flow Forward commodity price curve $0 - $17.65
Natural gas three-way collars $88
 Discounted cash flow Forward commodity price curve $0 - $0.12
 _______________________
Commodity (1)
The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gasFair ValueValuation TechniqueUnobservable InputRange
(In thousands)
Oil three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high$2,828 Discounted cash flowForward commodity price expected to be paid or received within the settlement period.curve$0 - $9.00
Natural gas collars$1,117 Discounted cash flowForward commodity price curve$0 - $0.48

 _______________________
1.The commodity contracts detailed in this category include non-exchange-traded crude oil three-way collars and natural gas 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, 20182019 reflected that the risk of non-performance was immaterial.


Fair Value of Other Financial Instruments


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


At SeptemberJune 30, 2018,2019, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (composed of bank and money market accounts - classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature.


Based on the borrowing rates available to us for credit agreement debt with similar terms and maturities and considering the risk of our non-performance, long-term debt under ourthe Unit and Superior credit agreements approximate theirits fair value and at SeptemberJune 30, 20182019 we did not have anyhad $103.5 million of outstanding borrowings under the Unit and $7.5 million under the Superior credit agreements. We had no borrowing under either the Unit or Superior credit agreement. Borrowings from our Unit credit agreementCredit agreements at December 31, 2017 were $178.0 million. These borrowings would be2018. Borrowings under these agreements are 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 SeptemberJune 30, 20182019 and December 31, 20172018 were $643.9$645.6 million and $642.3$644.5 million,, respectively. We estimate the fair value of the Notes using quoted marked prices at SeptemberJune 30, 20182019 and December 31, 20172018 was $655.5$592.4 million and $649.7$600.5 million,, respectively. The Notes would be classified as Level 2.


Fair Value of Non-Financial Instruments


The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the

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calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the company’s AROs is presented in Note 7 – Asset Retirement Obligations.


NOTE 12 – LEASES

Operating Leases under ASC 840

We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; and Pinedale, Wyoming under the terms of operating leases expiring through December 2021. We own our corporate headquarters in Tulsa, Oklahoma. We also have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. As of December 31, 2018, future minimum rental payments under the terms of the leases under ASC 840 were approximately $4.6 million, $1.7 million, and $0.4 million in 2019 through 2021, respectively.

Operating Leases under ASC 842

Adoption of Accounting Standards Codification (“ASC”) Topic 842, “Leases." We adopted Topic 842 on January 1, 2019, using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are not adjusted and continue to be reported under the accounting standards in effect for those periods.

We determine whether a contract is or contains a lease at inception of the contract based on whether an identified asset exists and whether we have the right to obtain substantially all of the benefit of the assets and to control its use over the full term of the agreement. When available, we use the rate implicit in the lease to discount lease payments to present value; however, most of our leases do not provide a readily determinable implicit rate. Therefore, we must estimate our incremental borrowing rate considering both the revolving credit rates and a credit notching approach to discount the lease payments based on information available at lease commencement. There are no material residual value guarantees and no restrictions or covenants included in the our lease agreements. Certain of our leases include provisions for variable payments. These variable payments are typically determined based on a measure of throughput or actual days or another measure of usage and are not included in the calculation of lease liabilities and right-of-use assets.

Related to our oil and natural gas segment, our short-term lease costs include those that are recognized in profit or loss during the period and those that are capitalized as part of the cost of another asset in accordance with other U.S. GAAP. As the costs related to our drilling and production activities are reflected at our net ownership consistent with the principals of proportional consolidation, and lease commitments are generally considered gross as the operator, the costs may not reasonably reflect the company’s short-term lease commitments. As of June 30, 2019, we had an average working interest of 94% in our operated properties.

Practical Expedients and Policies Elected. We elected the hindsight expedient, which allows us to use hindsight in assessing lease term; the package of practical expedients permitted under the guidance, which among other things, allowed us to carry forward the historical lease classification; and the land easement expedient, which allowed us to apply the guidance prospectively at adoption for land easements on existing agreements.We applied the short-term policy election, which allowed us to exclude from recognition on the balance sheet leases with an initial term of 12 months or less. We considered quantitative and qualitative factors when determining the application of the practical expedient that allowed us not to separate lease and non-lease components and are accounting for the agreements as a single lease component.

We routinely enter into related party agreements between our three segments. These agreements have been evaluated under the guidance of ASC 842. Routinely, our oil and natural gas segment contracts for the use of drilling equipment from our drilling segment.

We have determined that the contracting of our drilling segment's drilling rigs will be accounted for under ASC 606 as the service has been deemed the predominate component of the contract per the lessor practical expedient.

Adoption. Adoption of Topic 842 resulted in new operating lease assets and lease liabilities on our Unaudited Condensed Consolidated Balance Sheet of $3.7 million and $3.5 million, respectively, as of January 1, 2019, which represents noncash operating activity. The immaterial difference between the lease assets and lease liabilities was recorded as an adjustment to the beginning balance of retained earnings, which represents the cumulative impact of adopting the standard. Our accounting for finance leases remained substantially unchanged.

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

The following table shows supplemental cash flow information related to leases for the six months of June 30, 2019:
Amount
(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases$1,616 
Financing cash flows for finance leases1,980 
Lease liabilities recognized in exchange for new operating lease right of use assets5 

The following table shows information about our lease assets and liabilities included in our Unaudited Condensed Consolidated Balance Sheet as of June 30, 2019:
Classification on the Consolidated Balance SheetJune 30,
2019
(In thousands)
Assets
Operating right of use assetsRight of use assets$8,302 
Finance right of use assetsProperty, plant, and equipment, net18,416 
Total right of use assets$26,718 
Liabilities
Current liabilities:
Operating lease liabilitiesCurrent operating lease liabilities$4,519 
Finance lease liabilitiesCurrent portion of other long-term liabilities4,081 
Non-current liabilities:
Operating lease liabilitiesOperating lease liabilities3,556 
Finance lease liabilitiesOther long-term liabilities5,319 
Total lease liabilities$17,475 

The following table shows certain information related to the lease costs for our finance and operating leases for the three and six months ended June 30, 2019:
Three Months EndedSix Months Ended
June 30, June 30,
20192019
(In thousands)
Components of total lease cost:
Amortization of finance leased assets$995 $1,980 
Interest on finance lease liabilities100 211 
Operating lease cost1,052 1,651 
Short-term lease cost (1)
12,038 22,012 
Variable lease cost84 190 
Total lease cost$14,269 $26,044 
_______________________
1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $9.0 million and $14.7 million, respectively.

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The following table shows certain information related to the weighted average remaining lease terms and the weighted average discount rates for our operating and finance leases:
Weighted Average Remaining Lease Term
Weighted Average Discount
Rate (1)
(In years)
Operating leases2.26.34%  
Finance leases2.24.00%  
_______________________
1.Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.

The following table sets forth the maturity of our operating lease liabilities as of June 30, 2019:
Amount
(In thousands)
Ending July 1,
2020$4,902 
20212,642 
2022839 
2023196 
202412 
2025 and beyond81 
Total future payments8,672 
Less: Interest597 
Present value of future minimum operating lease payments8,075 
Less: Current portion4,519 
Total long-term operating lease payments$3,556 

As of June 30, 2019, we had one additional lease for $0.1 million that had not started. That lease will start later in 2019 with a term of two years.

Finance Leases

In 2014, Superior entered into finance lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $4.1 million current portion of the finance lease obligations is included in current portion of other long-term liabilities and the non-current portion of $5.3 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of June 30, 2019. These finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $3.2 million and $0.4 million, respectively, at June 30, 2019. Annual payments, net of maintenance and interest, average $4.3 million annually through 2021. At the end of the term, Superior has the option to purchase the assets at 10% of their then fair market value.

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The following table sets forth the maturity of our finance lease liabilities as of June 30, 2019:
Amount
Ending July 1,(In thousands)
2020 $6,168 
2021 6,672 
2022 180 
Total future payments13,020 
Less payments related to:
Maintenance3,196 
Interest424 
Present value of future minimum finance lease payments9,400 
Less: Current portion4,081 
Total long-term finance lease payments$5,319 

NOTE 1213 – 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 own our corporate headquarters in Tulsa, Oklahoma. 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 $5.1 million, $2.1 million, $0.6 million, and less than $0.1 million in twelve-month periods beginning October 1, 2018 (and through 2021), respectively. Total rent expense incurred was $7.2 million and $6.4 million for the first nine months of 2018 and 2017, respectively.

In 2014, Superior signed 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, 2018 (and through the end of 2021) are $6.2 million, $6.2 million, and $5.3 million. Total maintenance and interest remaining related to these leases are $4.6 million and $0.8 million, respectively at September 30, 2018. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, Superior has the option to purchase the assets at 10% of their then fair market value.


The 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 madehad no repurchases of approximately $1,700 and $2,900 in the first ninesix months of 2018 and 2017, respectively.2018. The partnerships were terminated in the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million net of Unit's interest.


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


We have not historically experienced any environmental liability while being a contract driller since the greatest portion of that risk is borne by the operator. Any liabilities we have incurred have been small and have beenwere resolved while the drilling rig iswas on the location and the cost has been includedlocation. Those costs were in the direct cost of drilling the well.


During the second quarter of 2018, as part of the Superior transaction, we entered into a contractual obligation that commits us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. This amount is already included in our future drilling plan.plans. For each dollar of the $150.0 million that we do not spend (over the three year period), we would forgo receiving $0.58 of future distributions from our 50% ownership interest in our consolidated mid-stream subsidiary. IfAt June 30, 2019, if we elected not to drill or spend any additional money in the designated area over the three year period,before December 31, 2021, the maximum amount we could forgo from distributions would be $87.0$74.0 million. Total spent towards the $150.0 million as of June 30, 2019 was $22.4 million.


For the next twelve12 months, we have committed to purchase approximately $10.1$1.6 million of new drilling rig components.components and casing.


NOTE 1314 – VARIABLE INTEREST ENTITY ARRANGEMENTS


On April 3, 2018 we sold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior will be governed and managed under the Amended and Restated Limited Liability Company Agreement and the MSA. The MSA is between our affiliate, SPC Midstream Operating, L.L.C. (the Operator) and Superior. The Operator is owned 100% by Unit Corporation. Under the guidance in ASC 810, Consolidation, we have determined that Superior is a VIE. The two variable interests applicable to Unit include the 50% equity investment in Superior and the MSA. The MSA houses the power to direct the activities that most significantly impact Superior's operating performance. The MSA is a separate variable interest. Unit through the MSA has the power to direct Superior’s most significant
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activities; reciprocally the equity investors lack the power to direct the activities that most significantly impact the entity’s economic performance. Because of this, Unit is considered the primary beneficiary. There have been no changes to the primary beneficiary during the quarter ended SeptemberJune 30, 2018.2019.


As the primary beneficiary of this VIE, we consolidate in theour financial statements the financial position, results of operations, and cash flows of this VIE, and all intercompany balances and transactions between us and the VIE are eliminated in theour consolidated financial statements. Cash distributions of income, net of agreed on expenses, and estimated expenses are allocated to the equity owners as specified in the relevant agreements.


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


As the Operator, we provide services, such aslike operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $250,000.$255,970. Superior's creditors have no recourse to our general credit. Superior's credit agreement is not guaranteed by Unit. The obligations under Superior's credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.


The carrying value of Superior's assets and liabilities, after eliminations of any intercompany transactions and balances, in the consolidated balance sheets were as follows:
June 30,
2019		December 31,
2018
 (In thousands)
Current assets:
Cash and cash equivalents$2 $5,841 
Accounts receivable 19,500 33,207 
Prepaid expenses and other4,185 1,049 
Total current assets23,687 40,097 
Property and equipment:
Gas gathering and processing equipment798,503 767,388 
Transportation equipment3,152 3,086 
801,655 770,474 
Less accumulated depreciation, depletion, amortization, and impairment387,845 364,740 
Net property and equipment413,810 405,734 
Right of use asset6,221 — 
Other assets15,330 17,551 
Total assets$459,048 $463,382 
Current liabilities:
Accounts payable$14,807 $32,214 
Accrued liabilities4,296 3,688 
Current operating lease liability3,576 — 
Current portion of other long-term liabilities6,970 6,875 
Total current liabilities29,649 42,777 
Long-term debt7,500 — 
Operating lease liability2,451 — 
Other long-term liabilities11,449 14,687 
Total liabilities$51,049 $57,464 

  September 30,
2018
  (In thousands)
   
Current assets:  
Cash and cash equivalents $9,039
Accounts receivable 29,991
Prepaid expenses and other 2,756
Total current assets 41,786
Property and equipment:  
Gas gathering and processing equipment 751,715
Transportation equipment 3,064
  754,779
Less accumulated depreciation, depletion, amortization, and impairment 353,476
Net property and equipment 401,303
Other assets 15,411
Total assets $458,500
   
Current liabilities:  
Accounts payable $28,183
Accrued liabilities 3,574
Current portion of other long-term liabilities 6,836
Total current liabilities 38,593
Long-term debt less debt issuance costs —
Other long-term liabilities 16,126
Total liabilities $54,719
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NOTE 1415 – EQUITY

At-the-Market (ATM) Common Stock Program

On April 4, 2017, we signed a Distribution Agreement (the Agreement) with a sales agent, under which we could offer and sell, from time to time, through the sales agent shares of our common stock, par value $.20 per share (the Shares), up to an aggregate offering price of $100.0 million. Net proceeds from any of these sales could be used to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.

On May 2, 2018, we terminated the Distribution Agreement. The Distribution Agreement was terminable at will on written notification by us with no penalty. As of the date of termination, we had sold 787,547 shares of our common stock under the Distribution Agreement resulting in net proceeds of approximately $18.6 million. We paid the sales agent a commission of 2.0% of the gross sales price per share sold. As a result of the termination, there will be no more sales of our common stock under the Distribution Agreement.
 
Accumulated Other Comprehensive Income (Loss)


Components of accumulated other comprehensive income (loss) were as follows for the three months ended SeptemberJune 30:
  2018 2017
  (In thousands)
Unrealized appreciation on securities, before tax $(51) $53
Tax benefit (expense) 13
(1) 
(20)
Unrealized appreciation on securities, net of tax $(38) $33
2019 2018 
(In thousands)
Unrealized appreciation (loss) on securities, before tax$(39)$46 
Tax benefit (expense)9 

(11)
(1)
Unrealized appreciation (loss) on securities, net of tax$(30)$35 
_______________________
(1)Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

1.Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Changes in accumulated other comprehensive income (loss) by component, net of tax, for the three months ended SeptemberJune 30 are as follows:
Net Gains (Loss) on Equity Securities
 Net Gains on Equity Securities2019 2018 
 2018 2017(In thousands)
 (In thousands)
Balance at June 30: $(65) $20
Balance at March 31:Balance at March 31:$(457)$(100)
Unrealized appreciation (loss) before reclassifications (38)
(1) 
33
Unrealized appreciation (loss) before reclassifications(30)

35 
(1)
Amounts reclassified from accumulated other comprehensive income —
 —
Amounts reclassified from accumulated other comprehensive income— — 
Net current-period other comprehensive income (loss) (38) 33
Net current-period other comprehensive income (loss)(30)35 
Balance at September 30: $(103) $53
Balance at June 30:Balance at June 30:$(487)$(65)
_______________________
(1)Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

1.Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Components of accumulated other comprehensive income (loss) were as follows for the ninesix months ended SeptemberJune 30:
  2018 2017
  (In thousands)
Unrealized appreciation (loss) on securities, before tax $(239) $85
Tax benefit (expense) 60
(1) 
(32)
Unrealized appreciation (loss) on securities, net of tax $(179) $53
_______________________
(1)Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

2019 2018 
(In thousands)
Unrealized loss on securities, before tax$(8)$(188)
Tax benefit2 47 
(1)
Unrealized loss on securities, net of tax$(6)$(141)

_______________________
1.Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Changes in accumulated other comprehensive income by component, net of tax, for the ninesix months ended SeptemberJune 30 are as follows:
  Net Gains on Equity Securities
  2018 2017
  (In thousands)
Balance at December 31, 2017 $63
 $—
Adjustment due to ASU 2018-02 13
(1) 
—
Balance at January 1: 76
 —
Unrealized appreciation (loss) before reclassifications (179)
(1) 
53
Amounts reclassified from accumulated other comprehensive income —
 —
Net current-period other comprehensive income (loss) (179) 53
Balance at September 30: $(103) $53
Net Gains (Loss) on Equity Securities
2019 2018 
(In thousands)
Prior year balance at December 31:$(481)$63 
Adjustment due to ASU 2018-02— 13 
(1)
Balance at January 1:(481)76 
Unrealized loss before reclassifications(6)(141)
(1)
Amounts reclassified from accumulated other comprehensive income— — 
Net current-period other comprehensive loss(6)(141)
Balance at June 30:$(487)$(65)
_______________________
(1)Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

1.Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

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NOTE 1516 – INDUSTRY SEGMENT INFORMATION


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


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


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



The following tables provide certain information about the operations of each of our segments:
  Three Months Ended September 30, 2018
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues: (1)
            
Oil and natural gas $111,623
 $—
 $—
 $—
 $—
 $111,623
Contract drilling —
 58,012
 —
 —
 (7,400) 50,612
Gas gathering and processing —
 —
 82,882
 —
 (25,059) 57,823
Total revenues 111,623
 58,012
 82,882
 —
 (32,459) 220,058
Expenses:            
Operating costs:            
Oil and natural gas 33,400
 —
 —
 —
 (1,261) 32,139
Contract drilling —
 38,246
 —
 —
 (6,214) 32,032
Gas gathering and processing —
 —
 66,932
 3,808
 (27,606) 43,134
Total operating costs 33,400
 38,246
 66,932
 3,808
 (35,081) 107,305
Depreciation, depletion, and amortization 35,460
 14,889
 11,265
 1,923
 —
 63,537
Total expenses 68,860
 53,135
 78,197
 5,731
 (35,081) 170,842
General and administrative —
 —
 —
 9,278
 —
 9,278
Gain on disposition of assets (7) (230) (16) —
 —
 (253)
Income (loss) from operations 42,770
 5,107
 4,701
 (15,009) 2,622
 40,191
Loss on derivatives —
 —
 —
 (4,385) —
 (4,385)
Interest, net —
 —
 (381) (7,564) —
 (7,945)
Other —
 —
 —
 3,814
 (3,808) 6
Income (loss) before income taxes $42,770
 $5,107
 $4,320
 $(23,144) $(1,186) $27,867

Three Months Ended June 30, 2019
 Oil and Natural GasContract DrillingMid-streamCorporate and OtherEliminationsTotal Consolidated
 (In thousands)
Revenues: (1)
Oil and natural gas$77,815 $— $— $— $— $77,815 
Contract drilling— 50,773 — — (7,736)43,037 
Gas gathering and processing— — 54,630 — (10,336)44,294 
Total revenues77,815 50,773 54,630 — (18,072)165,146 
Expenses:
Operating costs:
Oil and natural gas37,519 — — — (1,277)36,242 
Contract drilling— 36,390 — — (7,082)29,308 
Gas gathering and processing— — 41,550 — (9,059)32,491 
Total operating costs37,519 36,390 41,550 — (17,418)98,041 
Depreciation, depletion, and amortization38,751 13,504 12,102 1,935 — 66,292 
Total expenses76,270 49,894 53,652 1,935 (17,418)164,333 
General and administrative— — — 10,064 — 10,064 
Gain on disposition of assets(60)(296)(66)— — (422)
Income (loss) from operations1,605 1,175 1,044 (11,999)(654)(8,829)
Gain on derivatives— — — 7,927 — 7,927 
Interest, net— — (345)(8,650)— (8,995)
Other— — — 6 — 6 
Income (loss) before income taxes$1,605 $1,175 $699 $(12,716)$(654)$(9,891)
_______________________
(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.

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


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Three Months Ended June 30, 2018
 Three Months Ended September 30, 2017 Oil and Natural GasContract DrillingMid-streamCorporate and OtherEliminationsTotal Consolidated
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands)
 (In thousands)
Revenues:            
Revenues: (1)
Revenues: (1)
Oil and natural gas $85,470
 $—
 $—
 $—
 $—
 $85,470
Oil and natural gas$102,318 $— $— $— $— $102,318 
Contract drilling —
 55,588
 —
 —
 (3,969) 51,619
Contract drilling— 52,767 — — (5,841)46,926 
Gas gathering and processing —
 —
 69,057
 —
 (17,658) 51,399
Gas gathering and processing— — 75,406 — (21,347)54,059 
Total revenues 85,470
 55,588
 69,057
 —
 (21,627) 188,488
Total revenues102,318 52,767 75,406 — (27,188)203,303 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 35,082
 —
 —
 —
 (1,171) 33,911
Oil and natural gas33,682 — — — (1,264)32,418 
Contract drilling —
 38,115
 —
 —
 (3,368) 34,747
Contract drilling— 36,921 — — (5,027)31,894 
Gas gathering and processing —
 —
 54,602
 —
 (16,486) 38,116
Gas gathering and processing— — 59,786 — (20,083)39,703 
Total operating costs 35,082
 38,115
 54,602
 —
 (21,025) 106,774
Total operating costs33,682 36,921 59,786 — (26,374)104,015 
Depreciation, depletion, and amortization 26,460
 15,280
 10,880
 1,913
 —
 54,533
Depreciation, depletion, and amortization31,554 13,726 11,175 1,918 — 58,373 
Total expenses 61,542
 53,395
 65,482
 1,913
 (21,025) 161,307
Total expenses65,236 50,647 70,961 1,918 (26,374)162,388 
General and administrative expense —
 —
 —
 9,235
 —
 9,235
General and administrative expense— — — 8,712 — 8,712 
(Gain) loss on disposition of assets 1
 (68) (14) —
 —
 (81)
Gain on disposition of assetsGain on disposition of assets(59)(57)(45)— — (161)
Income (loss) from operations 23,927
 2,261
 3,589
 (11,148) (602) 18,027
Income (loss) from operations37,141 2,177 4,490 (10,630)(814)32,364 
Loss on derivatives —
 —
 —
 (2,614) —
 (2,614)Loss on derivatives— — — (14,461)— (14,461)
Interest, net —
 —
 —
 (9,944) —
 (9,944)Interest, net— — (304)(7,425)— (7,729)
Other —
 —
 —
 5
 —
 5
Other— — — 5 — 5 
Income (loss) before income taxes $23,927
 $2,261
 $3,589
 $(23,701) $(602) $5,474
Income (loss) before income taxes$37,141 $2,177 $4,186 $(32,511)$(814)$10,179 

_______________________

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.
  Nine Months Ended September 30, 2018
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues: (1)
            
Oil and natural gas $317,040
 $—
 $—
 $—
 $—
 $317,040
Contract drilling —
 161,489
 —
 —
 (17,962) 143,527
Gas gathering and processing —
 —
 232,938
 —
 (65,012) 167,926
Total revenues 317,040
 161,489
 232,938
 —
 (82,974) 628,493
Expenses:            
Operating costs:            
Oil and natural gas 104,234
 —
 —
 —
 (3,715) 100,519
Contract drilling —
 111,121
 —
 —
 (15,528) 95,593
Gas gathering and processing —
 —
 185,738
 7,384
 (68,681) 124,441
Total operating costs 104,234
 111,121
 185,738
 7,384
 (87,924) 320,553
Depreciation, depletion, and amortization 97,797
 41,927
 33,493
 5,759
 —
 178,976
Total expenses 202,031
 153,048
 219,231
 13,143
 (87,924) 499,529
General and administrative expense —
 —
 —
 28,752
 —
 28,752
Gain on disposition of assets (136) (314) (95) (30) —
 (575)
Income (loss) from operations 115,145
 8,755
 13,802
 (41,865) 4,950
 100,787
Loss on derivatives —
 —
 —
 (25,608) —
 (25,608)
Interest, net —
 —
 (834) (24,844) —
 (25,678)
Other —
 —
 —
 7,401
 (7,384) 17
Income (loss) before income taxes $115,145
 $8,755
 $12,968
 $(84,916) $(2,434) $49,518
32
_______________________
(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.

Table of Contents

Six Months Ended June 30, 2019
Oil and Natural GasContract DrillingMid-streamCorporate and OtherEliminationsTotal Consolidated
(In thousands)
Revenues: (1)
Oil and natural gas$163,910 $— $— $— $— $163,910 
Contract drilling— 108,972 — — (14,780)94,192 
Gas gathering and processing— — 125,139 — (28,404)96,735 
Total revenues163,910 108,972 125,139 — (43,184)354,837 
Expenses:
Operating costs:
Oil and natural gas71,527 — — — (2,571)68,956 
Contract drilling— 73,775 — — (13,066)60,709 
Gas gathering and processing— — 97,679 — (25,833)71,846 
Total operating costs71,527 73,775 97,679 — (41,470)201,511 
Depreciation, depletion, and amortization74,518 26,203 23,828 3,869 — 128,418 
Total expenses146,045 99,978 121,507 3,869 (41,470)329,929 
General and administrative expense— — — 19,805 — 19,805 
(Gain) loss on disposition of assets(138)1,449 (108)(10)— 1,193 
Income (loss) from operations18,003 7,545 3,740 (23,664)(1,714)3,910 
Gain on derivatives— — — 995 — 995 
Interest, net— — (681)(16,852)— (17,533)
Other— — — 11 — 11 
Income (loss) before income taxes$18,003 $7,545 $3,059 $(39,510)$(1,714)$(12,617)
_______________________ ____________________ 
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

33
Table of Contents
Six Months Ended June 30, 2018
 Nine Months Ended September 30, 2017 Oil and Natural GasContract DrillingMid-streamCorporate and OtherEliminationsTotal Consolidated
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands)
 (In thousands)
Revenues:            
Revenues: (1)
Revenues: (1)
Oil and natural gas $256,241
 $—
 $—
 $—
 $—
 $256,241
Oil and natural gas$205,417 $— $— $— $— $205,417 
Contract drilling —
 137,617
 —
 —
 (9,558) 128,059
Contract drilling— 103,477 — — (10,562)92,915 
Gas gathering and processing —
 —
 198,632
 —
 (48,139) 150,493
Gas gathering and processing— — 150,056 — (39,953)110,103 
Total revenues 256,241
 137,617
 198,632
 —
 (57,697) 534,793
Total revenues205,417 103,477 150,056 — (50,515)408,435 
Expenses:            Expenses:
Operating costs:            Operating costs:
Oil and natural gas 99,349
 —
 —
 —
 (3,476) 95,873
Oil and natural gas70,834 — — — (2,454)68,380 
Contract drilling —
 99,794
 —
 —
 (8,581) 91,213
Contract drilling— 72,875 — — (9,314)63,561 
Gas gathering and processing —
 —
 156,525
 —
 (44,663) 111,862
Gas gathering and processing— — 118,806 — (37,499)81,307 
Total operating costs 99,349
 99,794
 156,525
 —
 (56,720) 298,948
Total operating costs70,834 72,875 118,806 — (49,267)213,248 
Depreciation, depletion, and amortization 71,544
 41,896
 32,547
 5,558
 —
 151,545
Depreciation, depletion, and amortization62,337 27,038 22,228 3,836 — 115,439 
Total expenses 170,893
 141,690
 189,072
 5,558
 (56,720) 450,493
Total expenses133,171 99,913 141,034 3,836 (49,267)328,687 
General and administrative expense —
 —
 —
 26,902
 —
 26,902
General and administrative expense— — — 19,474 — 19,474 
Gain on disposition of assets (176) (106) (58) (813) —
 (1,153)Gain on disposition of assets(129)(84)(79)(30)— (322)
Income (loss) from operations 85,524
 (3,967) 9,618
 (31,647) (977) 58,551
Income (loss) from operations72,375 3,648 9,101 (23,280)(1,248)60,596 
Gain on derivatives —
 —
 —
 21,019
 —
 21,019
Loss on derivativesLoss on derivatives— — — (21,223)— (21,223)
Interest, net —
 —
 —
 (28,807) —
 (28,807)Interest, net— — (453)(17,280)— (17,733)
Other —
 —
 —
 14
 —
 14
Other— — — 11 — 11 
Income (loss) before income taxes $85,524
 $(3,967) $9,618
 $(39,421) $(977) $50,777
Income (loss) before income taxes$72,375 $3,648 $8,648 $(61,772)$(1,248)$21,651 

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

NOTE 1617 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION


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


For purposes of the following footnote:


•we are referred to as "Parent",
•the direct subsidiaries are 100% owned by the Parent and the guarantee is full and unconditional and joint and several and referred to as "Combined Guarantor Subsidiaries", and
•Superior and its subsidiaries and the Operator are referred to as "Non-Guarantor Subsidiaries."


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


34
Table of Contents
Condensed Consolidating Balance Sheets (Unaudited)
June 30, 2019
ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents$508 $159 $2 $— $669 
Accounts receivable, net of allowance for doubtful accounts of $2,494 (Guarantor of $1,289 and Parent of $1,205) 1,775 71,965 22,058 (5,922)89,876 
Materials and supplies— 516 — — 516 
Current derivative asset8,513 — — — 8,513 
Income taxes receivable2,405 — — — 2,405 
Assets held for sale— 19,500 — — 19,500 
Prepaid expenses and other1,990 2,931 4,185 — 9,106 
Total current assets15,191 95,071 26,245 (5,922)130,585 
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties— 6,212,323 — — 6,212,323 
Unproved properties not being amortized— 336,214 — — 336,214 
Drilling equipment— 1,284,295 — — 1,284,295 
Gas gathering and processing equipment— — 798,503 — 798,503 
Saltwater disposal systems— 69,212 — — 69,212 
Corporate land and building— 59,080 — — 59,080 
Transportation equipment9,731 17,136 3,152 — 30,019 
Other28,824 29,076 — — 57,900 
38,555 8,007,336 801,655 — 8,847,546 
Less accumulated depreciation, depletion, amortization, and impairment30,652 5,871,078 387,845 — 6,289,575 
Net property and equipment7,903 2,136,258 413,810 — 2,557,971 
Intercompany receivable1,046,308 — — (1,046,308)— 
Goodwill— 62,808 — — 62,808 
Investments1,166,768 — — (1,166,768)— 
Right of use asset58 2,080 6,221 (57)8,302 
Other assets8,731 9,802 15,330 — 33,863 
Total assets$2,244,959 $2,306,019 $461,606 $(2,219,055)$2,793,529 

35
Table of Contents
 September 30, 2018
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
ASSETS         
Current assets:         
Cash and cash equivalents$82,267
 $251
 $9,039
 $—
 $91,557
Accounts receivable, net of allowance for doubtful accounts of $2,450 (Guarantor of $1,245 and Non-Guarantor of $1,205)1,374
 92,078
 28,671
 —
 122,123
Materials and supplies—
 505
 —
 —
 505
Current derivative asset—
 —
 —
 —
 —
Prepaid expenses and other3,125
 3,538
 2,756
 —
 9,419
Total current assets86,766
 96,372
 40,466
 —
 223,604
Property and equipment:         
Oil and natural gas properties on the full cost method:         
Proved properties—
 5,901,661
 —
 —
 5,901,661
Unproved properties not being amortized—
 332,886
 —
 —
 332,886
Drilling equipment—
 1,632,540
 —
 —
 1,632,540
Gas gathering and processing equipment—
 —
 751,715
 —
 751,715
Saltwater disposal systems—
 67,074
 —
 —
 67,074
Corporate land and building—
 59,081
 —
 —
 59,081
Transportation equipment9,273
 16,766
 3,064
 —
 29,103
Other28,506
 28,244
 —
 —
 56,750
 37,779
 8,038,252
 754,779
 —
 8,830,810
Less accumulated depreciation, depletion, amortization, and impairment25,922
 5,945,762
 353,476
 —
 6,325,160
Net property and equipment11,857
 2,092,490
 401,303
 —
 2,505,650
Intercompany receivable907,907
 —
 —
 (907,907) —
Goodwill—
 62,808
 —
 —
 62,808
Investments1,248,309
 1,500
 —
 (1,248,309) 1,500
Other assets5,605
 6,186
 15,412
 —
 27,203
Total assets$2,260,444
 $2,259,356
 $457,181
 $(2,156,216) $2,820,765
June 30, 2019
ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable$10,892 $110,379 $15,779 $(5,921)$131,129 
Accrued liabilities22,080 17,837 5,725 (467)45,175 
Current operating lease liability24 925 3,576 (6)4,519 
Current portion of other long-term liabilities1,083 5,834 6,970 — 13,887 
Total current liabilities34,079 134,975 32,050 (6,394)194,710 
Intercompany debt— 1,046,159 149 (1,046,308)— 
Long-term debt less debt issuance costs749,090 — 7,500 — 756,590 
Non-current derivative liability256 — — — 256 
Operating lease liability34 1,122 2,451 (51)3,556 
Other long-term liabilities14,669 77,088 11,449 (506)102,700 
Deferred income taxes56,471 86,014 — — 142,485 
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, 55,536,916 shares issued 10,590 — — — 10,590 
Capital in excess of par value638,769 45,921 197,042 (242,963)638,769 
Contributions from Unit— — 1,145 (1,145)— 
Accumulated other comprehensive loss— (487)— — (487)
Retained earnings741,001 915,227 6,461 (921,688)741,001 
Total shareholders’ equity attributable to Unit Corporation1,390,360 960,661 204,648 (1,165,796)1,389,873 
Non-controlling interests in consolidated subsidiaries— — 203,359 — 203,359 
Total shareholders' equity1,390,360 960,661 408,007 (1,165,796)1,593,232 
Total liabilities and shareholders’ equity$2,244,959 $2,306,019 $461,606 $(2,219,055)$2,793,529 



36
Table of Contents
 September 30, 2018
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY         
Current liabilities:         
Accounts payable$28,116
 $90,543
 $24,893
 $—
 $143,552
Accrued liabilities36,444
 26,583
 4,716
 —
 67,743
Income taxes payable1,051
 —
 —
 —
 1,051
Current derivative liability13,067
 —
 —
 —
 13,067
Current portion of other long-term liabilities966
 6,348
 6,836
 —
 14,150
Total current liabilities79,644
 123,474
 36,445
 —
 239,563
Intercompany debt—
 906,296
 1,086
 (907,382) —
Bonds payable less debt issuance costs643,921
 —
 —
 —
 643,921
Non-current derivative liabilities1,542
 —
 —
 —
 1,542
Other long-term liabilities12,790
 72,494
 16,126
 —
 101,410
Deferred income taxes54,707
 110,257
 —
 —
 164,964
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, 54,063,705 shares issued10,414
 —
 —
 —
 10,414
Capital in excess of par value626,746
 45,921
 197,042
 (242,963) 626,746
Contributions from Unit—
 —
 525
 (525) —
Accumulated other comprehensive loss—
 (103) —
 —
 (103)
Retained earnings830,680
 1,001,017
 4,329
 (1,005,346) 830,680
Total shareholders’ equity attributable to Unit Corporation1,467,840
 1,046,835
 201,896
 (1,248,834) 1,467,737
Non-controlling interests in consolidated subsidiaries—
 —
 201,628
 —
 201,628
Total shareholders' equity1,467,840
 1,046,835
 403,524
 (1,248,834) 1,669,365
Total liabilities and shareholders’ equity$2,260,444
 $2,259,356
 $457,181
 $(2,156,216) $2,820,765
December 31, 2018
ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents$403 $208 $5,841 $— $6,452 
Accounts receivable, net of allowance for doubtful accounts of $2,531 (Guarantor of $1,326 and Parent of $1,205) 2,539 94,526 36,676 (14,344)119,397 
Materials and supplies— 473 — — 473 
Current derivative asset12,870 — — — 12,870 
Income tax receivable243 1,811 — — 2,054 
Assets held for sale— 22,511 — — 22,511 
Prepaid expenses and other1,993 3,560 1,049 — 6,602 
Total current assets18,048 123,089 43,566 (14,344)170,359 
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties— 6,018,568 — — 6,018,568 
Unproved properties not being amortized— 330,216 — — 330,216 
Drilling equipment— 1,284,419 — — 1,284,419 
Gas gathering and processing equipment— — 767,388 — 767,388 
Saltwater disposal systems— 68,339 — — 68,339 
Corporate land and building— 59,081 — — 59,081 
Transportation equipment9,273 17,165 3,086 — 29,524 
Other28,584 28,923 — — 57,507 
37,857 7,806,711 770,474 — 8,615,042 
Less accumulated depreciation, depletion, amortization, and impairment27,504 5,790,481 364,741 — 6,182,726 
Net property and equipment10,353 2,016,230 405,733 — 2,432,316 
Intercompany receivable950,916 — — (950,916)— 
Goodwill— 62,808 — — 62,808 
Investments1,160,444 — — (1,160,444)— 
Other assets8,225 6,793 17,552 — 32,570 
Total assets$2,147,986 $2,208,920 $466,851 $(2,125,704)$2,698,053 



37
Table of Contents
 December 31, 2017
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
ASSETS         
Current assets:         
Cash and cash equivalents$510
 $191
 $—
 $—
 $701
Accounts receivable, net of allowance for doubtful accounts of $2,450 (Guarantor of $1,245 and Non-Guarantor of $1,205)154
 83,442
 27,916
 —
 111,512
Materials and supplies—
 505
 —
 —
 505
Current derivative asset721
 —
 —
 —
 721
Prepaid expenses and other2,986
 2,370
 877
 —
 6,233
Total current assets4,371
 86,508
 28,793
 —
 119,672
Property and equipment:         
Oil and natural gas properties on the full cost method:         
Proved properties—
 5,712,813
 —
 —
 5,712,813
Unproved properties not being amortized—
 296,764
 —
 —
 296,764
Drilling equipment—
 1,593,611
 —
 —
 1,593,611
Gas gathering and processing equipment—
 —
 726,236
 —
 726,236
Saltwater disposal systems—
 62,618
 —
 —
 62,618
Corporate land and building—
 59,080
 —
 —
 59,080
Transportation equipment9,270
 17,423
 2,938
 —
 29,631
Other28,039
 25,400
 —
 —
 53,439
 37,309
 7,767,709
 729,174
 —
 8,534,192
Less accumulated depreciation, depletion, amortization, and impairment21,268
 5,807,757
 322,425
 —
 6,151,450
Net property and equipment16,041
 1,959,952
 406,749
 —
 2,382,742
Intercompany receivable1,155,725
 —
 —
 (1,155,725) —
Goodwill—
 62,808
 —
 —
 62,808
Investments1,044,709
 1,500
 —
 (1,044,709) 1,500
Other assets5,373
 6,328
 3,029
 —
 14,730
Total assets$2,226,219
 $2,117,096
 $438,571
 $(2,200,434) $2,581,452
December 31, 2018
ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable$8,697 $122,610 $32,214 $(13,576)$149,945 
Accrued liabilities28,230 16,409 5,493 (468)49,664 
Current portion of other long-term liabilities812 6,563 6,875 — 14,250 
Total current liabilities37,739 145,582 44,582 (14,044)213,859 
Intercompany debt— 948,707 2,209 (950,916)— 
Long-term debt less debt issuance costs644,475 — — — 644,475 
Non-current derivative liability293 — — — 293 
Other long-term liabilities13,134 73,713 14,687 (300)101,234 
Deferred income taxes60,983 83,765 — — 144,748 
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, 54,055,600 shares issued 10,414 — — — 10,414 
Capital in excess of par value628,108 45,921 197,042 (242,963)628,108 
Contributions from Unit— — 792 (792)— 
Accumulated other comprehensive loss— (481)— — (481)
Retained earnings752,840 911,713 4,976 (916,689)752,840 
Total shareholders’ equity attributable to Unit Corporation1,391,362 957,153 202,810 (1,160,444)1,390,881 
Non-controlling interests in consolidated subsidiaries— — 202,563 — 202,563 
Total shareholders' equity1,391,362 957,153 405,373 (1,160,444)1,593,444 
Total liabilities and shareholders’ equity$2,147,986 $2,208,920 $466,851 $(2,125,704)$2,698,053 



38
Table of Contents
 December 31, 2017
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY         
Current liabilities:         
Accounts payable$13,124
 $81,334
 $18,190
 $—
 $112,648
Accrued liabilities26,165
 19,134
 3,224
 —
 48,523
Current derivative liability7,763
 —
 —
 —
 7,763
Current portion of other long-term liabilities657
 8,501
 3,844
 —
 13,002
Total current liabilities47,709
 108,969
 25,258
 —
 181,936
Intercompany debt—
 870,582
 285,143
 (1,155,725) —
Long-term debt178,000
 —
 —
 —
 178,000
Bonds payable less debt issuance costs642,276
 —
 —
 —
 642,276
Other long-term liabilities11,257
 77,566
 11,380
 —
 100,203
Deferred income taxes1,480
 85,443
 46,554
 —
 133,477
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, 52,880,134 shares issued10,280
 —
 —
 —
 10,280
Capital in excess of par value535,815
 45,921
 15,549
 (61,470) 535,815
Accumulated other comprehensive income—
 63
 —
 —
 63
Retained earnings799,402
 928,552
 54,687
 (983,239) 799,402
Total shareholders’ equity attributable to Unit Corporation1,345,497
 974,536
 70,236
 (1,044,709) 1,345,560
Non-controlling interests in consolidated subsidiaries—
 —
 —
 —
 —
Total shareholders' equity1,345,497
 974,536
 70,236
 (1,044,709) 1,345,560
Total liabilities and shareholders’ equity$2,226,219
 $2,117,096
 $438,571
 $(2,200,434) $2,581,452


Condensed Consolidating Statements of IncomeOperations (Unaudited)

Three Months Ended June 30, 2019
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Revenues$— $128,588 $54,630 $(18,072)$165,146 
Expenses:
Operating costs— 73,909 41,550 (17,418)98,041 
Depreciation, depletion, and amortization1,935 52,255 12,102 — 66,292 
General and administrative— 10,064 — — 10,064 
Gain on disposition of assets— (356)(66)— (422)
Total operating costs1,935 135,872 53,586 (17,418)173,975 
Income (loss) from operations(1,935)(7,284)1,044 (654)(8,829)
Interest, net(8,650)— (345)— (8,995)
Gain on derivatives7,927 — — — 7,927 
Other, net6 — — — 6 
Income (loss) before income taxes(2,652)(7,284)699 (654)(9,891)
Income tax benefit(848)(1,026)— — (1,874)
Equity in net earnings from investment in subsidiaries, net of taxes(6,705)— — 6,705 — 
Net income (loss)(8,509)(6,258)699 6,051 (8,017)
Less: net income attributable to non-controlling interest— — 492 — 492 
Net income (loss) attributable to Unit Corporation$(8,509)$(6,258)$207 $6,051 $(8,509)
Three Months Ended June 30, 2018
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Revenues$— $155,085 $75,406 $(27,188)$203,303 
Expenses:
Operating costs— 70,603 59,786 (26,374)104,015 
Depreciation, depletion, and amortization1,918 45,280 11,175 — 58,373 
General and administrative— 8,655 57 — 8,712 
Gain on disposition of assets— (116)(45)— (161)
Total operating costs1,918 124,422 70,973 (26,374)170,939 
Income (loss) from operations(1,918)30,663 4,433 (814)32,364 
Interest, net(7,425)— (304)— (7,729)
Loss on derivatives(14,461)— — — (14,461)
Other, net5 — — — 5 
Income (loss) before income taxes(23,799)30,663 4,129 (814)10,179 
Income tax expense (benefit)(6,029)7,803 255 — 2,029 
Equity in net earnings from investment in subsidiaries, net of taxes23,558 — — (23,558)— 
Net income5,788 22,860 3,874 (24,372)8,150 
Less: net income attributable to non-controlling interest— — 2,362 — 2,362 
Net income attributable to Unit Corporation$5,788 $22,860 $1,512 $(24,372)$5,788 

39
Table of Contents
Three Months Ended September 30, 2018Six Months Ended June 30, 2019
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total ConsolidatedParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands)(In thousands)
Revenues$—
 $169,635
 $82,882
 $(32,459) $220,058
Revenues$— $272,882 $125,139 $(43,184)$354,837 
Expenses:         Expenses:
Operating costs—
 71,646
 66,932
 (31,273) 107,305
Operating costs— 145,302 97,679 (41,470)201,511 
Depreciation, depletion, and amortization1,923
 50,349
 11,265
 —
 63,537
Depreciation, depletion, and amortization3,869 100,721 23,828 — 128,418 
General and administrative—
 9,252
 26
 —
 9,278
General and administrative— 19,805 — — 19,805 
Gain on disposition of assets—
 (237) (16) —
 (253)
(Gain) loss on disposition of assets(Gain) loss on disposition of assets(10)1,311 (108)— 1,193 
Total operating costs1,923
 131,010
 78,207
 (31,273) 179,867
Total operating costs3,859 267,139 121,399 (41,470)350,927 
Income from operations(1,923) 38,625
 4,675
 (1,186) 40,191
Income (loss) from operationsIncome (loss) from operations(3,859)5,743 3,740 (1,714)3,910 
Interest, net(7,564) —
 (381) —
 (7,945)Interest, net(16,852)— (681)— (17,533)
Loss on derivatives(4,385) —
 —
 —
 (4,385)
Gain on derivativesGain on derivatives995 — — — 995 
Other, net6
 (1) 1
 —
 6
Other, net11 — — — 11 
Income (loss) before income taxes(13,866) 38,624
 4,295
 (1,186) 27,867
Income (loss) before income taxes(19,705)5,743 3,059 (1,714)(12,617)
Income tax expense (benefit)(3,688) 9,839
 593
 —
 6,744
Income tax expense (benefit)(4,547)2,229 — — (2,318)
Equity in net earnings from investment in subsidiaries, net of taxes29,077
 —
 —
 (29,077) —
Net income18,899
 28,785
 3,702
 (30,263) 21,123
Equity in net earnings from investment in subsidiaries, net of taxEquity in net earnings from investment in subsidiaries, net of tax3,145 — — (3,145)— 
Net income (loss)Net income (loss)(12,013)3,514 3,059 (4,859)(10,299)
Less: net income attributable to non-controlling interest—
 —
 2,224
 —
 2,224
Less: net income attributable to non-controlling interest— — 1,714 — 1,714 
Net income attributable to Unit Corporation$18,899
 $28,785
 $1,478
 $(30,263) $18,899
Net income (loss) attributable to Unit CorporationNet income (loss) attributable to Unit Corporation$(12,013)$3,514 $1,345 $(4,859)$(12,013)

Six Months Ended June 30, 2018
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Revenues$— $308,894 $150,056 $(50,515)$408,435 
Expenses:
Operating costs— 143,709 118,806 (49,267)213,248 
Depreciation, depletion, and amortization3,836 89,375 22,228 — 115,439 
General and administrative— 16,884 2,590 — 19,474 
Gain on disposition of assets(30)(213)(79)— (322)
Total operating costs3,806 249,755 143,545 (49,267)347,839 
Income (loss) from operations(3,806)59,139 6,511 (1,248)60,596 
Interest, net(17,280)— (453)— (17,733)
Loss on derivatives(21,223)— — — (21,223)
Other, net11 1 (1)— 11 
Income (loss) before income taxes(42,298)59,140 6,057 (1,248)21,651 
Income tax expense (benefit)(10,668)15,460 844 — 5,636 
Equity in net earnings from investment in subsidiaries, net of tax45,283 — — (45,283)— 
Net income13,653 43,680 5,213 (46,531)16,015 
Less: net income attributable to non-controlling interest— — 2,362 — 2,362 
Net income attributable to Unit Corporation$13,653 $43,680 $2,851 $(46,531)$13,653 

 Three Months Ended September 30, 2017
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
Revenues$—
 $141,058
 $69,057
 $(21,627) $188,488
Expenses:         
Operating costs—
 73,197
 54,603
 (21,026) 106,774
Depreciation, depletion, and amortization1,913
 41,740
 10,880
 —
 54,533
General and administrative—
 7,083
 2,152
 —
 9,235
Gain on disposition of assets—
 (67) (14) —
 (81)
Total operating costs1,913
 121,953
 67,621
 (21,026) 170,461
Income (loss) from operations(1,913) 19,105
 1,436
 (601) 18,027
Interest, net(9,776) —
 (168) —
 (9,944)
Loss on derivatives(2,614) —
 —
 —
 (2,614)
Other, net5
 —
 —
 —
 5
Income (loss) before income taxes(14,298) 19,105
 1,268
 (601) 5,474
Income tax expense (benefit)(5,626) 7,003
 392
 —
 1,769
Equity in net earnings from investment in subsidiaries, net of taxes12,377
 —
 —
 (12,377) —
Net income3,705
 12,102
 876
 (12,978) 3,705
Less: net income attributable to non-controlling interest—
 —
 —
 —
 —
Net income attributable to Unit Corporation$3,705
 $12,102
 $876
 $(12,978) $3,705
40

 Nine Months Ended September 30, 2018
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
Revenues$—
 $478,529
 $232,938
 $(82,974) $628,493
Expenses:         
Operating costs—
 215,355
 185,738
 (80,540) 320,553
Depreciation, depletion, and amortization5,759
 139,724
 33,493
 —
 178,976
General and administrative—
 26,136
 2,616
 —
 28,752
Gain on disposition of assets(30) (450) (95) —
 (575)
Total operating costs5,729
 380,765
 221,752
 (80,540) 527,706
Income (loss) from operations(5,729) 97,764
 11,186
 (2,434) 100,787
Interest, net(24,844) —
 (834) —
 (25,678)
Loss on derivatives(25,608) —
 —
 —
 (25,608)
Other, net17
 —
 —
 —
 17
Income (loss) before income taxes(56,164) 97,764
 10,352
 (2,434) 49,518
Income tax expense (benefit)(14,356) 25,299
 1,437
 —
 12,380
Equity in net earnings from investment in subsidiaries, net of tax74,360
 —
 —
 (74,360) —
Net income32,552
 72,465
 8,915
 (76,794) 37,138
Less: net income attributable to non-controlling interest—
 —
 4,586
 —
 4,586
Net income attributable to Unit Corporation$32,552
 $72,465
 $4,329
 $(76,794) $32,552
Table of Contents
 Nine Months Ended September 30, 2017
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
Revenues$—
 $393,858
 $198,632
 $(57,697) $534,793
Expenses:         
Operating costs—
 199,143
 156,525
 (56,720) 298,948
Depreciation, depletion, and amortization5,558
 113,440
 32,547
 —
 151,545
General and administrative—
 20,880
 6,022
 —
 26,902
Gain on disposition of assets(813) (282) (58) —
 (1,153)
Total operating costs4,745
 333,181
 195,036
 (56,720) 476,242
Income (loss) from operations(4,745) 60,677
 3,596
 (977) 58,551
Interest, net(28,276) —
 (531) —
 (28,807)
Gain on derivatives21,019
 —
 —
 —
 21,019
Other, net14
 —
 —
 —
 14
Income (loss) before income taxes(11,988) 60,677
 3,065
 (977) 50,777
Income tax expense (benefit)(4,895) 25,357
 1,622
 —
 22,084
Equity in net earnings from investment in subsidiaries, net of tax35,786
 —
 —
 (35,786) —
Net income28,693
 35,320
 1,443
 (36,763) 28,693
Less: net income attributable to non-controlling interest—
 —
 —
 —
 —
Net income attributable to Unit Corporation$28,693
 $35,320
 $1,443
 $(36,763) $28,693

Condensed Consolidating Statements of Comprehensive Income (Loss) (Unaudited)
 Three Months Ended September 30, 2018
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
Net income$18,899
 $28,785
 $3,702
 $(30,263) $21,123
Other comprehensive income, net of taxes:         
Unrealized loss on securities, net of tax ($13)—
 (38) —
 —
 (38)
Comprehensive income18,899
 28,747
 3,702
 (30,263) 21,085
Less: Comprehensive income attributable to non-controlling interests—
 —
 2,224
 —
 2,224
Comprehensive income attributable to Unit Corporation$18,899
 $28,747
 $1,478
 $(30,263) $18,861
Three Months Ended June 30, 2019
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Net income (loss)$(8,509)$(6,258)$699 $6,051 $(8,017)
Other comprehensive income (loss), net of taxes:
Unrealized loss on securities, net of tax ($9)— (30)— — (30)
Comprehensive income (loss)(8,509)(6,288)699 6,051 (8,047)
Less: Comprehensive income attributable to non-controlling interests— — 492 — 492 
Comprehensive income (loss) attributable to Unit Corporation$(8,509)$(6,288)$207 $6,051 $(8,539)
 Three Months Ended September 30, 2017
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
Net income$3,705
 $12,102
 $876
 $(12,978) $3,705
Other comprehensive income, net of taxes:         
Unrealized gain on securities, net of tax of $20—
 33
 —
 —
 33
Comprehensive income3,705
 12,135
 876
 (12,978) 3,738
Less: Comprehensive income attributable to non-controlling interests—
 —
 —
 —
 —
Comprehensive income attributable to Unit Corporation$3,705
 $12,135
 $876
 $(12,978) $3,738

Nine Months Ended September 30, 2018Three Months Ended June 30, 2018
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands) (In thousands)
Net income$32,552
 $72,465
 $8,915
 $(76,794) $37,138
Net income$5,788 $22,860 $3,874 $(24,372)$8,150 
Other comprehensive income, net of taxes:         Other comprehensive income, net of taxes:
Unrealized loss on securities, net of tax of ($60)—
 (179) —
 —
 (179)
Unrealized gain on securities, net of tax of $11Unrealized gain on securities, net of tax of $11— 35 — — 35 
Comprehensive income32,552
 72,286
 8,915
 (76,794) 36,959
Comprehensive income5,788 22,895 3,874 (24,372)8,185 
Less: Comprehensive income attributable to non-controlling interests—
 —
 4,586
 —
 4,586
Less: Comprehensive income attributable to non-controlling interests— — 2,362 — 2,362 
Comprehensive income attributable to Unit Corporation$32,552
 $72,286
 $4,329
 $(76,794) $32,373
Comprehensive income attributable to Unit Corporation$5,788 $22,895 $1,512 $(24,372)$5,823 

Six Months Ended June 30, 2019
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Net income (loss)$(12,013)$3,514 $3,059 $(4,859)$(10,299)
Other comprehensive income (loss), net of taxes:
Unrealized loss on securities, net of tax of ($2)— (6)— — (6)
Comprehensive income (loss)(12,013)3,508 3,059 (4,859)(10,305)
Less: Comprehensive income attributable to non-controlling interests— — 1,714 — 1,714 
Comprehensive income (loss) attributable to Unit Corporation$(12,013)$3,508 $1,345 $(4,859)$(12,019)
Six Months Ended June 30, 2018
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
Net income$13,653 $43,680 $5,213 $(46,531)$16,015 
Other comprehensive income, net of taxes:
Unrealized loss on securities, net of tax of ($47)— (141)— — (141)
Comprehensive income13,653 43,539 5,213 (46,531)15,874 
Less: Comprehensive income attributable to non-controlling interests— — 2,362 — 2,362 
Comprehensive income attributable to Unit Corporation$13,653 $43,539 $2,851 $(46,531)$13,512 

41
Table of Contents
 Nine Months Ended September 30, 2017
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
Net income$28,693
 $35,320
 $1,443
 $(36,763) $28,693
Other comprehensive income, net of taxes:         
Unrealized gain on securities, net of tax of $32—
 53
 —
 —
 53
Comprehensive income28,693
 35,373
 1,443
 (36,763) 28,746
Less: Comprehensive income attributable to non-controlling interests—
 —
 —
 —
 —
Comprehensive income attributable to Unit Corporation$28,693
 $35,373
 $1,443
 $(36,763) $28,746


Condensed Consolidating Statements of Cash Flows (Unaudited)
 Nine Months Ended September 30, 2018
 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
 (In thousands)
OPERATING ACTIVITIES:         
Net cash provided by (used in) operating activities(103,436) 215,350
 (3,984) 128,605
 236,535
INVESTING ACTIVITIES:         
Capital expenditures22
 (275,434) (28,642) —
 (304,054)
Producing properties and other acquisitions—
 (769) —
 —
 (769)
Proceeds from disposition of assets30
 25,199
 87
 —
 25,316
Net cash provided by (used in) investing activities52
 (251,004) (28,555) —
 (279,507)
FINANCING ACTIVITIES:         
Borrowings under credit agreement69,200
 —
 2,000
 —
 71,200
Payments under credit agreement(247,200) —
 (2,000) —
 (249,200)
Intercompany borrowings (advances), net248,343
 35,714
 (155,977) (128,080) —
Payments on capitalized leases—
 —
 (2,869) —
 (2,869)
Proceeds from investments of non-controlling interest102,958
 —
 197,042
 —
 300,000
Contributions from Unit—
 —
 525
 (525) —
Transaction costs associated with sale of non-controlling interest(2,303) —
 —
 —
 (2,303)
Book overdrafts14,143
 —
 2,857
 —
 17,000
Net cash provided by financing activities185,141
 35,714
 41,578
 (128,605) 133,828
Net increase in cash and cash equivalents81,757
 60
 9,039
 —
 90,856
Cash and cash equivalents, beginning of period510
 191
 —
 —
 701
Cash and cash equivalents, end of period$82,267
 $251
 $9,039
 $—
 $91,557
Nine Months Ended September 30, 2017Six Months Ended June 30, 2019
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
(In thousands) (In thousands)
OPERATING ACTIVITIES:         OPERATING ACTIVITIES:
Net cash provided by operating activities822
 149,963
 34,007
 —
 184,792
Net cash provided by (used in) operating activitiesNet cash provided by (used in) operating activities$(8,023)$111,615 $23,943 $(34)$127,501 
INVESTING ACTIVITIES:         INVESTING ACTIVITIES:
Capital expenditures(3,595) (152,055) (11,742) —
 (167,392)Capital expenditures(100)(212,982)(33,556)— (246,638)
Producing properties and other acquisitions—
 (55,429) —
 —
 (55,429)Producing properties and other acquisitions— (3,313)— — (3,313)
Proceeds from disposition of assets955
 19,124
 58
 —
 20,137
Proceeds from disposition of assets10 7,247 83 — 7,340 
Other—
 (1,500) —
 —
 (1,500)
Net cash used in investing activities(2,640) (189,860) (11,684) —
 (204,184)Net cash used in investing activities(90)(209,048)(33,473)— (242,611)
FINANCING ACTIVITIES:         FINANCING ACTIVITIES:
Borrowings under credit agreement251,401
 —
 —
 —
 251,401
Borrowings under credit agreement238,800 — 32,400 — 271,200 
Payments under credit agreement(250,100) —
 —
 —
 (250,100)Payments under credit agreement(135,300)— (24,900)— (160,200)
Intercompany borrowings (advances), net(20,483) 39,839
 (19,356) —
 —
Intercompany borrowings (advances), net(96,311)97,384 (1,107)34 — 
Payments on capitalized leases—
 —
 (2,967) —
 (2,967)
Proceeds from common stock issued, net of issue costs18,623
 —
 —
 —
 18,623
Payments on finance leasesPayments on finance leases— — (1,980)— (1,980)
Employee taxes paid by withholding sharesEmployee taxes paid by withholding shares(4,073)— — — (4,073)
Distributions to non-controlling interestDistributions to non-controlling interest919 — (1,837)— (918)
Book overdrafts2,364
 —
 —
 —
 2,364
Book overdrafts4,183 — 1,115 — 5,298 
Net cash provided by (used in) financing activities1,805
 39,839
 (22,323) —
 19,321
Net decrease in cash and cash equivalents(13) (58) —
 —
 (71)
Net cash provided by financing activitiesNet cash provided by financing activities8,218 97,384 3,691 34 109,327 
Net increase (decrease) in cash and cash equivalentsNet increase (decrease) in cash and cash equivalents105 (49)(5,839)— (5,783)
Cash and cash equivalents, beginning of period517
 376
 —
 —
 893
Cash and cash equivalents, beginning of period403 208 5,841 — 6,452 
Cash and cash equivalents, end of period$504
 $318
 $—
 $—
 $822
Cash and cash equivalents, end of period$508 $159 $2 $— $669 

Six Months Ended June 30, 2018
 ParentCombined Guarantor SubsidiariesCombined Non-Guarantor SubsidiariesConsolidating AdjustmentsTotal Consolidated
 (In thousands)
OPERATING ACTIVITIES:
Net cash provided by operating activities$(96,111)$145,227 $(16,469)$126,993 $159,640 
INVESTING ACTIVITIES:
Capital expenditures(13)(173,097)(16,806)— (189,916)
Producing properties and other acquisitions— (962)— — (962)
Proceeds from disposition of assets30 23,427 71 — 23,528 
Net cash used in investing activities17 (150,632)(16,735)— (167,350)
FINANCING ACTIVITIES:
Borrowings under credit agreement69,200 — 2,000 — 71,200 
Payments under credit agreement(247,200)— (2,000)— (249,200)
Intercompany borrowings (advances), net276,460 5,468 (154,935)(126,993)— 
Payments on finance leases— — (1,901)— (1,901)
Employee taxes paid by withholding shares(4,947)— — — (4,947)
Proceeds from investments of non-controlling interest102,958 — 197,042 — 300,000 
Transaction costs associated with sale of non-controlling interest(2,254)— — — (2,254)
Book overdrafts(1,581)— — — (1,581)
Net cash provided by (used in) financing activities192,636 5,468 40,206 (126,993)111,317 
Net increase (decrease) in cash and cash equivalents96,542 63 7,002 — 103,607 
Cash and cash equivalents, beginning of period510 191 — — 701 
Cash and cash equivalents, end of period$97,052 $254 $7,002 $— $104,308 



42



NOTE 17 – SUBSEQUENT EVENT

On October 18, 2018, we signed the fifth amendment to the Unit credit agreement originally scheduled to mature on April 10, 2020. The Fifth Amendment, among other things, (i) extends the termTable of the Unit credit agreement to October 18, 2023, subject to certain conditions; (ii) reduces the pricing for borrowing and non-use fees; and (iii) eliminates the requirement that the company maintain a senior indebtedness to consolidated EBITDA ratio. The total commitment of credit and the borrowing base both remain unchanged at $425.0 million.Contents

A copy of the Fifth Amendment is filed as Exhibit 10.1 to this report.

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


Management’s Discussion and Analysis (MD&A) provides you with an understanding of our operating results and financial condition by focusing on changes in certain key measures from year to year or period to period. MD&A is organized into these sections:


•General;
•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 (and any amendments thereto) in conjunction with your review of the information below and our unaudited condensed consolidated financial statements and related notes.


Unless otherwise indicated or required by the content, when used in this report the terms “company,” “Unit,” “us,” “our,” “we,” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers to Superior Pipeline Company, L.L.C. of which we own 50%.


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


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

Business Outlook


As discussed in other parts of this report, our success depends, to a large degree, on the prices we receive for our oil and natural gas production, the demand for oil, natural gas, and NGLs, and the demand for our drilling rigs which influences the amounts we can charge for those drilling rigs. While our operations are all within the United States, events outside the United States affect us and our industry.


Fluctuating commodity prices worldwide during the past several years brought aboutcan result in significant and adverse changes to our industry and us. IndustryDepressed commodity prices, particularly for the extended time, can result in industry wide reductions in drilling activity and spending reducedwhich reduce the rates for and the number of our drilling rigs we were able to put to work. Such industry wide reductions in drilling activity and spending for extended periods also reduces the rates for and the number of our drilling rigs we can work. In addition, sustained lower commodity prices impact the liquidity condition of some of our industry partners and customers, which could limit their ability to meet their financial obligations to us.


Recently,During the last several years, commodity prices have improved. Reflecting that improvement,been volatile. Our oil and natural gas segment began using two to three drilling rigs throughout 2017. With improved commodity prices during the first quarter of 2018, our oil and natural gas segment put four of our drilling rigs to work and increased the number to six drilling rigs for a brief period during

the third quarter of 2018. We have subsequently reduced our operated rig count. Our contract drilling segment finished constructing its 11th BOSS drilling rig and that drilling rig was placed into service in mid-July. During the second quarter and third quarter of 2018, we were awarded term contracts to build our 12th and 13th BOSS drilling rigs. Construction is in progress and the drilling rigs will be placed into service instarted the first quarter of 2019. Rig utilization fluctuated over2019 with four drilling rigs operating, increased to six during March and through mid-second quarter and ended the past year duesecond quarter with four drilling rigs operating. Our plans are to commodity prices changing and budget constraints on operatorsnow substantially reduce our borrowings under our credit agreement by year-end.

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The following chart reflects the significant fluctuations in the fourth quarterprices for oil and natural gas:

unt-20190630_g2.jpg
The following chart reflects the significant fluctuations in the prices for NGLs:

unt-20190630_g3.jpg
_________________________
1.NGLs prices reflect a weighted-average, based on production, of 2017. We expect commodity pricesMont Belvieu and budget constraints on operators to continue to affect rig utilization through 2018.Conway prices.


Other recent improvements:

We have not incurred a non-cash ceiling test write-down since 2016. WeIn our oil and gas segment, we had no write-downwrite-downs in 2018 or in the third quarterfirst six months of 2018 nor the third quarter of 2017.2019. 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
44
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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 SeptemberJune 30, 2018,2019, and only adjust the 12-month average price to an estimated fourththird quarter ending average (holding October 2018July 2019 prices constant for the remaining two months of the fourththird quarter of 2018)2019), our forward looking expectation is that we will notwould recognize an impairment of $107 million pre-tax in the fourththird quarter of 2018. But commodity prices (and other factors) remain volatile and they could negatively affect2019. The actual amount of any write-down may vary significantly from this estimate depending on the 12-month average price resulting infinal future determination.

For 2019, we believe the potential for a future impairment.

In 2018, our oil and natural gas segment plansnumber of gross wells we will drill to participate in drilling 95-105be 85-95 wells (depending on future commodity prices). In 2017,

Our contract drilling segment completed the construction of one additional BOSS drilling rigs during the third quarter of 2018. During the second quarter and third quarter of 2018, we drilled 70 wells up from 21were awarded term contracts to build our 12th and 13th BOSS drilling rigs. Construction was completed for one of these in 2016January and it was placed into service for a third-party operator. Early in the first quarter of 2019, the other contract was terminated but we were able to find another third-party operator and it was placed into service in February. Our 14th BOSS drilling rig was contracted during the second quarter of 2019. Construction has started and the new drilling rig will be placed into service in the fourth quarter of 2019. Rig utilization fluctuated over the past year due to commodity prices changing and budget constraints on operators. We expect commodity prices and budget constraints on operators to continue to affect rig utilization throughout 2019. During 2018, utilization increased cash flow resulting from improvementto a high of 36 drilling rigs but with a decline in commodity prices.prices during the fourth quarter, declined to 32 drilling rigs as of December 31, 2018 and continued to decline to 24 drilling rigs as of June 30, 2019.


On April 3,In December 2018, the company completed the sale of 50% of the ownership interests in Superiorwe removed from service 41 drilling rigs, some older top drives, and certain drill pipe that has been reclassed to SP Investor Holdings, LLC, a holding company jointly owned by OPTrust'Assets held for sale.' At June 30, 2019, our drilling rig fleet totaled 57 drilling rigs.

During 2018, due to low ethane and funds managed and/or advised by Partners Group, a global private markets investment manager, for cash consideration of $300.0 million. Part of the proceeds from the sale were used to pay down our bank debt and the balance will be used to accelerate the drilling programresidue prices, we operated some of our upstream subsidiary, Unit Petroleum Company, make additional capital investmentsmid-stream processing facilities in Superior,ethane rejection mode which reduces the liquids sold. At the end of 2018 and for general working capital purposes.into the first part of 2019, as NGLs and gas prices improved, we began operating some of our mid-stream processing facilities in ethane recovery mode. We are continuing to monitor commodity prices to determine the most economical method in which to operate our processing facilities.


Executive Summary


Oil and Natural Gas


ThirdSecond quarter 20182019 production from our oil and natural gas segment was 4,359,0004,151,000 barrels of oil equivalent (Boe), ana increase of 3%1% over the secondfirst quarter of 20182019 and an increasea decrease of 7% over the third quarter of 2017, respectively. The increases for both comparative periods were primarily from new wells drilled during 2017 and the first nine months of 2018.

Third quarter 2018 oil and natural gas revenues increased 9% over the second quarter of 2018 and increased 31% over the third quarter of 2017. The increase over the second quarter of 2018 was due primarily to an increase in NGLs and natural gas production volumes and an increase in commodity prices partially offset by lower oil production volumes. The increase over the third quarter of 2017 was due primarily to higher oil and NGLs prices and higher production volumes.

Our oil prices for the third quarter of 2018 increased 2% over the second quarter of 2018 and increased 22% over the third quarter of 2017. Our NGLs prices increased 16% over the second quarter of 2018 and increased 40% over the third quarter of 2017. Our natural gas prices increased 4% over the second quarter of 2018 and decreased 4% from the third quarter of 2017.

Operating cost per Boe produced for the third quarter of 2018 decreased 4%1% from the second quarter of 2018, and decreased 12% fromrespectively. The increase over the thirdfirst quarter of 2017.2019 was primarily from a 14-day plant shut-down (12-days of which were in the first quarter of 2019) that resulted in a loss of slightly over 165 MBoe for the first quarter of 2019. The decrease from the second quarter of 2018 was primarily due to the 14-day plant shut-down (2-days of which were in the second quarter of 2019) and the associated delays in getting production ramped back up after the plant shutdown ended. We also had a series of weather related events in the Texas Panhandle and Oklahoma that caused well shut-ins and delays in operations.

Second quarter 2019 oil and natural gas revenues decreased 10% from the first quarter of 2019 and decreased 24% from the second quarter of 2018. The decreases were primarily from a decrease in commodity prices.

Our oil prices for the second quarter of 2019 increased 6% over the first quarter of 2019 and increased 6% over the second quarter of 2018. Our NGLs prices decreased 22% from the first quarter of 2019 and decreased 44% from the second quarter of 2018. Our natural gas prices decreased 26% from the first quarter of 2019 and decreased 15% from the second quarter of 2018.

Operating cost per Boe produced for the second quarter of 2019 increased 10% over the first quarter of 2019 and increased 13% over the second quarter of 2018. The increase over the first quarter of 2019 was primarily due to higher lease operating expenses from new wells drilled partially offset by lower general and administrative expenses and gross production taxes. The increase over the second quarter of 2018 was primarily due to higher lease operating expenses and increasedsaltwater disposal expenses and lower equivalent production partially offset by increased gross production tax expense. The decrease from the third quarterproduction.

45
Table of 2017 was primarily due to the reclassification of deducts from the ASC 606 revenue recognition standard.Contents

At SeptemberJune 30, 2018,2019, these derivatives were outstanding:
TermCommodityContracted Volume
Weighted Average 

Fixed Price
Contracted Market
Oct'18Jul'19 – Oct'19Natural gas – swap30,00060,000 MMBtu/day$3.0052.900 IF – NYMEX (HH)
Nov’18Nov'19 – Dec'18Dec'19Natural gas – swap20,00040,000 MMBtu/day$3.0132.900 IF – NYMEX (HH)
Jan'19Jul'19 – Dec'19Natural gas – swap10,000 MMBtu/day$2.810IF – NYMEX (HH)
Oct'18Natural gas – basis swap10,00020,000 MMBtu/day$(0.190)(0.659)NGPL TEXOKPEPL
Oct'18Jul'19 – Dec'18Dec'19Natural gas – basis swap10,000 MMBtu/day$(0.678)(0.625)PEPLNGL MIDCON
Oct'18Jul'19 – Dec'18Dec'19Natural gas – basis swap10,00030,000 MMBtu/day$(0.568)(0.265)NGPL MIDCONTEXOK
Nov’18Jan'20 – Dec'18Dec'20Natural gas – basis swap10,00030,000 MMBtu/day$(0.208)(0.275)NGPL TEXOK
Jul'19 – Dec'19Natural gas – collar20,000 MMBtu/day$2.63 - $3.03IF – NYMEX (HH)
Jan'19Jul'19 – Dec'19Natural gas – basis swap20,000 MMBtu/day$(0.659)PEPL
Jan'19 – Dec'19Natural gas – basis swap10,000 MMBtu/day$(0.625)NGL MIDCON
Jan'19 – Dec'19Natural gas – basis swap30,000 MMBtu/day$(0.265)NGPL TEXOK
Jan'20 – Dec'20Natural gas – basis swap30,000 MMBtu/day$(0.275)NGPL TEXOK
Oct'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Oct'18 – Dec'18Crude oil – swap4,000 Bbl/day$53.52WTI – NYMEX
Oct'18 – Dec'18Crude oil – price differential risk500 Bbl/day$7.00LLS/WTI
Oct'18 – Dec'18Crude oil – three-way collar2,000 Bbl/day$47.50 - $37.50 - $56.08WTI – NYMEX
Jan'19 – Dec'19Crude oil – three-way collar4,000 Bbl/day$61.25 - $51.25 - $72.93WTI – NYMEX


After September 30, 2018, the following derivatives were entered into:
TermCommodityContracted Volume
Weighted Average 
Fixed Price
Contracted Market
Jan'19 – Dec'19Natural gas – swap10,000 MMBtu/day$2.850IF – NYMEX (HH)
Jan'19 – Dec'19Natural gas – collar20,000 MMBtu/day$2.63 - $3.03IF – NYMEX (HH)
Jan'19 – Mar'19Natural gas – three-way collar10,000 MMBtu/day$3.00 - $2.75 - $4.35IF – NYMEX (HH)

For the ninethree months ended SeptemberJune 30, 2018,2019, we completed drilling 7363 gross wells (21.06(17.41 net wells). For all of 2018,2019, we anticipate participating in the drilling of approximately 95 to 10585-95 gross wells.Excluding a reduction in ARO liability and any possible acquisitions, our estimated 20182019 capital expenditures for this segment areis approximately $333.0 million.$265.0 million (slightly lower than the original $271.0 million to $315.0 million range) due to lower commodity prices. Our current 20182019 production guidance is approximately 17.117.0 to 17.317.2 MMBoe, an increase of 7-8% from 2017, although actual results continue to be subject to many factors.


Contract Drilling


The average number of drilling rigs we operated in the thirdsecond quarter of 20182019 was 34.228.6 compared to 31.4 and 32.2 in the first quarter of 2019 and 34.6 in the second quarter of 2018, and the third quarter of 2017, respectively. As of SeptemberJune 30, 2018, 342019, 24 of our drilling rigs were operating.


Revenue for the thirdsecond quarter of 2018 increased2019 decreased 16% from the first quarter of 2019 and decreased 8% from the second quarter of 2018. The decreases were primarily due to less drilling rigs operating.

Dayrates for the second quarter of 2019 averaged $18,491, an 1% increase over the first quarter of 2019 and a 7% increase over the second quarter of 2018 and decreased 2% from2018. The increase over the thirdfirst quarter of 2017.2019 was primarily due to lower dayrate drilling rigs being released and higher dayrate BOSS drilling rigs continuing to operate. The increase over the second quarter of 2018 was primarily due to increased utilization and dayrates. The decrease from the third quarter of 2017 was primarily due to increased eliminations with a large percentage of our drilling rig usage coming from our oil and gas segment in 2018 compared to 2017 partially offset by higher dayrates.

Dayrates for the third quarter of 2018 averaged $17,589, a 2%labor increase over the second quarter of 2018 and a 7% increase over the third quarter of 2017. The increase over the second quarter of 2018 was primarily due to general increases with the improving market and the addition of a BOSS drilling rig. The increase over the third quarter of 2017 was due to two labor increases passed through to contracted rigs rates and improving market dayrates.


Operating costs for the thirdsecond quarter of 2018 were essentially unchanged2019 decreased 7% from the first quarter of 2019 and decreased 8% from the second quarter of 2018 and decreased 8% from the third quarter of 2017.2018. The decrease from the third quarter of 2017 wasdecreases were both primarily due to increased eliminations with a larger percentage of ourless drilling rig usage coming from our oil and gas segment in 2018 and lower per day costs.rigs operating.


Currently, we have 2114 term drilling contracts with original terms ranging from six months to three years. FiveTwo are up for renewal in the third quarter of 2019, four in the fourth quarter of 2018, 13 in 2019, onefive in 2020, and twothree after 2020. The drilling rigs for the two expiring after 2020 are still under construction and will be placed into service in the first quarter of 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 who had signed term contracts have opted to release the drilling rig early and pay an early termination penalty for the remaining term of the contract. We recorded $4.8 million in early termination fees in the first quarter of 2019. We had no early termination fees for the second quarter of 2019.

All eleven13 of our existing BOSS drilling rigs are under contract.

Our estimated 20182019 capital expenditures for this segment is approximately $45.0 million (the midpoint of the original $30.0 million to $65.0 million range) due to the construction of our 14th BOSS drilling rig.

Our drilling rig personnel are approximately $73.0 million.

Competitiona key component to keep qualified labor continues to be an issuethe overall success of our drilling services. With the present conditions in the drilling industry, we face in this segment and in response, we implemented pay ratedo not anticipate increases in certain areasthe compensation paid to those personnel in the first quarter of 2018. 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.near term.


Mid-Stream


ThirdSecond quarter 20182019 liquids sold per day increased 4%9% over the first quarter of 2019 and increased 5% over the second quarter of 2018, and increased 32% overrespectively. The increase from the thirdfirst quarter of 2017, respectively.2019 was due to higher processed volumes and better recoveries at our processing facilities. The increase over the second quarter of 2018 was due to operating in higher recovery mode during the third quarter. The increase over the third quarter of 2017 was primarily due to increased volume available to process at our processing facilities due to additional well connectsconnections along with operating in higher recovery mode. For the thirdsecond quarter of 2018,2019, gas processed per day was essentially unchanged from increased 2% over the first quarter of 2019 and increased 3% over
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the second quarter of 2018 and increased 14% over the third quarter of 2017.2018. The increase over the thirdfirst quarter of 20172019 was primarily due to higher volumes from newassociated with wells connected mainly to our Cashion and Bellmon processing facilities. For the third quarter of 2018, gas gathered per day increased 6% and 8%facility. The increase over the second quarter of 2018 andwas mainly due to new wells connected to the thirdCashion facility. For the second quarter of 2017, respectively. The increases2019, gas gathered per day increased 4% and 19% over the first quarter of 2019 and the second quarter of 2018, and the third quarter of 2017 were primarilyrespectively. These increases are both due to connecting additional wells to our systems.gathering systems primarily in Pennsylvania and Oklahoma.


NGLs prices in the thirdsecond quarter of 2018 increased 8% over2019 decreased 26% from the prices received in the first quarter of 2019 and decreased 45% from the prices received in the second quarter of 2018 and increased 13% over the prices received in the third quarter of 2017.2018. 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 thirdsecond quarter of 2018 increased 9% over2019 decreased 17% from the first quarter of 2019 and decreased 18% from the second quarter of 2018 and increased 13% over the third quarter of 2017.2018. The increase over the second quarter of 2018 wasdecreases were both primarily due to higherlower gas and NGLs prices. The increase over the third quarter of 2017 was primarily due to higher purchased volumes and purchase prices.


In the Appalachian region at the Pittsburgh Mills gathering system, the average gathered volume for the thirdsecond quarter of 2018 increased to2019 was approximately 142.6206.4 MMcf per day afterday. In the first quarter of 2019, we added seven new infill wells latewhich accounted for the significant increase in the second quarter. All the new infill wells are currently online and flowing gas. We are completing construction of the new pipeline to connect the next scheduled well pad to our system. Construction of this pipeline is operationally complete and the improvements to the compressor station are expected to be completed early in the fourth quarter. We anticipate receiving production from this pad earlygathered volume in the first quarter. In the second quarter of 2019.

At2019, the Hemphill Texas system, average total throughput volume increased to 74.1 MMcf per day for the third quarter of 2018 and total production of NGLs increased to approximately 316,110 gallons per day. During the third quarter, we connected one new wellfrom these wells is declining as evidenced in the Buffalo Wallow area. This new well along with increased production from recently drilledlower volume as of June 2019. These wells in this area contributed to our increased throughput volume.are all long lateral wells. The increased liquid production was due to operating in ethane recovery mode. Unit Petroleum continues to operate a rig in the Buffalo Wallow area and we anticipate connecting additional wells to this system in the 4th quarter. Additionally, we have completed a construction project that increased our compression capacity at the Buffalo WallowKissick compressor station facilities located on the south end of the system have been upgraded and are able to accommodate expected additional volumes.  handle the increased volume from these new wells.


At the Cashion processing facility in central Oklahoma, total throughput volume for the second quarter of 20182019 averaged approximately 47.556.7 MMcf per day and total production of NGLsnatural gas liquids increased to approximately 233,700273,075 gallons per day. ThisWe are continuing to connect new wells to this system is operating at full processing capacity andfrom several third party producers. In 2019, we arehave connected 16 new wells to this system from several third party producers who continue to be active in the processarea. During the second quarter, we completed the addition of adding additional capacitythe new 60 MMcf per day Reeding processing facility on thisthe Cashion system. We have begun the relocation of aThis 60 MMcf per day processing plant was relocated from our Bellmon facility to the Cashion system. This $20.0 million plant expansion/relocation projectarea and is underway and will increasenow fully operational. The addition of this new processing facility increases our total processing capacity on the Cashion system to approximately 105 MMcf per day. This project is expected to be completed and operational

At the Hemphill processing facility located in the firstTexas panhandle, average total throughput volume for the second quarter of 2019. We2019 was 72.9 MMcf per day and total production of natural gas liquids was 288,762 gallons per day during this same period. Since the first of this year, we have connected eightsix new wells to this systemthe Hemphill system. The six new wells connected in the third quarter of 2018 and we2019 are continuing to connect additionalUnit Petroleum wells. There are no Unit Petroleum wells from a third party producer who is activecurrently being drilled in this area.


At the Segno gathering facility in Southeast Texas, gathered volume for the third quarter of 2018 averaged approximately 83.1 MMcf per day. At this facility, the existing gathering and dehydration capacity will allow us to gather up to 120 MMcf per day. In the third quarter of 2018, we added one new well to this system. Unit Petroleum is actively drilling in the Segno area, as well as, reworking and recompleting existing wells that are connected to our system which will continue to add additional volume.


Our estimated 20182019 capital expenditures for this segment areis approximately $50.0 million.$45.0 million (slightly higher than the original $35.0 million to $42.0 million range) due to the purchase of previously leased assets.


Financial Condition and Liquidity


Summary


Our financial condition and liquidity depends on the cash flow from our operations and borrowings under our credit agreements. Our cash flow is based primarily on:
 
•the amount of natural gas, oil, and NGLs we produce;
•the prices we receive for our natural gas, oil, and NGLs production;
•the demand for and the dayrates we receive for our drilling rigs; and
•the fees and margins we obtain from our natural gas gathering and processing contracts.


We believe we will have enough cash flow and liquidity to meet our obligations and remain in compliance with our debt covenants for the next twelve12 months. Our ability to meet our debt covenants (under our credit agreements 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 the Unit credit agreement, it could reduce the borrowing base and therefore reduce or limit our ability to incur indebtedness. We monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues, and work, where possible, with our lenders to address those issues ahead of time.
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 Nine Months Ended September 30, 
%
Change
 Six Months Ended June 30,%
Change
 2018 2017  2019 2018 %
Change
 (In thousands except percentages) (In thousands except percentages)
Net cash provided by operating activities $236,535
 $184,792
 28%Net cash provided by operating activities$127,501 $159,640 (20)%
Net cash used in investing activities (279,507) (204,184) 37%Net cash used in investing activities(242,611)(167,350)45 %
Net cash provided by financing activities 133,828
 19,321
 NM
Net cash provided by financing activities109,327 111,317 (2)%
Net increase (decrease) in cash and cash equivalents $90,856
 $(71)  Net increase (decrease) in cash and cash equivalents$(5,783)$103,607 


Cash Flows from Operating Activities


Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production, the quantity of oil, NGLs, and natural gas we produce, settlements of derivative contracts, and third-party demand for our drilling rigs and mid-stream services and the rates we obtain for those services. Our cash flows from operating activities are also affected by changes in working capital.


Net cash provided by operating activities in the first ninesix months of 2018 increased2019 decreased by $51.7$32.1 million as compared to the first ninesix months of 2017.2018. The increase resulted from increaseddecrease was primarily due to decreased operating profit in all three segmentsthe oil and gas segment and a smaller decrease in changes in operating assets and liabilities related to the timing of cash receipts and disbursements partially offset by decreasesincreases in cash for derivatives settled.


Cash Flows from Investing Activities


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



Cash flows used in investing activities increased by $75.3 million for the first ninesix months of 20182019 compared to the first ninesix months of 2017.2018. The change was due primarily to an increase in capital expenditures for development drilling and construction of BOSS drilling rigs partially offset byand a reduction in cash proceeds on the sale of cash spent on producing properties and other acquisitions.assets. See additional information on capital expenditures below under Capital Requirements.


Cash Flows from Financing Activities


Cash flows provided by financing activities increaseddecreased by $114.5$2.0 million for the first ninesix months of 20182019 compared to the first ninesix months of 2017.2018. The increasedecrease was primarily due to an increase in the proceeds from thenet borrowings under our credit agreements partially offset by sale of 50% interest in our mid-stream segment partially offset by the pay down of our outstanding debt under the Unit credit agreement.in 2018.


At SeptemberJune 30, 2018,2019, we had unrestricted cash and cash equivalents totaling $91.6$0.7 million and had not borrowed any$103.5 million of the $425.0 million orand $7.5 million of the $200.0 million we had elected to have available under either of the Unit orand Superior credit agreements, respectively. The credit agreements are used primarily for working capital and capital expenditures. On April 3, 2018, we paid down the outstanding debt under the Unit credit agreement.


Below, we summarize certain financial information as of SeptemberJune 30, 20182019 and 20172018 and for the ninesix months ended SeptemberJune 30, 20182019 and 2017:2018:
 June 30,%
Change
 2019 2018 
 (In thousands except percentages)
Working capital$(64,125)$26,330 NM  
Long-term debt less debt issuance costs$756,590 $643,371 18 %
Shareholders’ equity attributable to Unit Corporation$1,389,873 $1,444,250 (4)%
Net income (loss) attributable to Unit Corporation$(12,013)$13,653 (188)%
_________________________
1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

48
  September 30, 
%
Change
  2018 2017 
  (In thousands except percentages)
Working capital $(15,959) $(62,181) 74 %
Long-term debt less debt issuance costs $643,921
 $803,833
 (20)%
Unit Corporation's shareholders’ equity $1,467,737
 $1,251,905
 17 %
Net income attributable to Unit Corporation $32,552
 $28,693
 13 %
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Working Capital


Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative activity. We had negative working capital of $16.0$64.1 million and negativepositive working capital of $62.2$26.3 million as of SeptemberJune 30, 20182019 and 2017,2018, respectively. The increasedecrease in working capital is primarily due to increaseda decrease in accounts receivable due to lower revenues and by a decrease cash and cash equivalents from the sale of 50% interest in our mid-stream segment and increased accounts receivable due to increased revenuesin 2018 partially offset by increasedreduction in accounts payable due to increased activity in our drilling program and increased drilling rig utilization and the change in the value of outstanding derivatives.payable. The Unit and Superior credit agreements are used primarily for working capital and capital expenditures. At SeptemberJune 30, 2018,2019, we had not borrowed any$103.5 million of the $425.0 million orand $7.5 million of the $200.0 million available under the Unit or Superior credit agreements, respectively. The effect of our derivative contracts increased working capital by $8.5 million as of June 30, 2019 and decreased working capital by $13.1$18.4 million as of SeptemberJune 30, 2018 and increased working capital by $0.4 million as of September 30, 2017.2018.



This table summarizes certain operating information:
 Nine Months Ended  Six Months Ended
 September 30, 
%
Change
 June 30,%
Change
 2018 2017  2019 2018 %
Change
Oil and Natural Gas:      Oil and Natural Gas:
Oil production (MBbls) 2,121
 1,990
 7 %Oil production (MBbls)1,414 1,429 (1)%
NGLs production (MBbls) 3,702
 3,476
 7 %NGLs production (MBbls)2,417 2,425 —%
Natural gas production (MMcf) 41,572
 37,317
 11 %Natural gas production (MMcf)26,659 27,237 (2)%
Equivalent barrels (MBoe)Equivalent barrels (MBoe)8,274 8,393 (1)%
Average oil price per barrel received $56.40
 $47.62
 18 %Average oil price per barrel received$58.16 $55.76 4 %
Average oil price per barrel received excluding derivatives $65.89
 $46.99
 40 %Average oil price per barrel received excluding derivatives$55.86 $64.08 (13)%
Average NGLs price per barrel received $23.03
 $17.05
 35 %Average NGLs price per barrel received$14.11 $21.65 (35)%
Average NGLs price per barrel received excluding derivatives $23.55
 $17.05
 38 %Average NGLs price per barrel received excluding derivatives$14.11 $21.91 (36)%
Average natural gas price per Mcf received $2.35
 $2.50
 (6)%Average natural gas price per Mcf received$2.18 $2.40 (9)%
Average natural gas price per Mcf received excluding derivatives $2.26
 $2.55
 (11)%Average natural gas price per Mcf received excluding derivatives$2.11 $2.27 (7)%
Net impact of revenue recognition (ASC 606) per Boe (1)
Net impact of revenue recognition (ASC 606) per Boe (1)
$(1.26)$(0.82)(54)%
Average realized price per Boe receivedAverage realized price per Boe received$19.83 $22.70 (13)%
Average realized price per Boe received excluding derivativesAverage realized price per Boe received excluding derivatives$19.19 $23.77 (19)%
Contract Drilling:      Contract Drilling:
Average number of our drilling rigs in use during the period 32.7
 29.7
 10 %Average number of our drilling rigs in use during the period30.0 31.9 (6)%
Total number of drilling rigs owned at the end of the period 96
 95
 1 %Total number of drilling rigs owned at the end of the period57 95 (40)%
Average dayrate $17,327
 $16,120
 7 %Average dayrate$18,412 $17,184 7 %
Mid-Stream:      Mid-Stream:
Gas gathered—Mcf/day 393,414
 385,846
 2 %Gas gathered—Mcf/day457,859 382,005 20 %
Gas processed—Mcf/day 157,313
 133,986
 17 %Gas processed—Mcf/day163,725 155,799 5 %
Gas liquids sold—gallons/day 651,979
 518,054
 26 %Gas liquids sold—gallons/day681,070 627,305 9 %
Number of natural gas gathering systems 22
(1) 
25
 (12)%Number of natural gas gathering systems21 22 (5)%
Number of processing plants 14
 13
 8 %Number of processing plants12 14 (14)%
_______________________
(1)    In1.Pursuant to accounting guidance on revenue recognition (ASC 606); gathering, processing, and transportation costs are reflected as a deduction from revenue instead of as an expense when we arrange for another company to provide the first quarter of 2018, our mid-stream segment transferred two natural gas gathering systems to our oil and natural gas segment.good or service.


Oil and Natural Gas Operations


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


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Based on our first ninesix months of 20182019 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of derivatives, would cause a corresponding $447,000$427,000 per month ($5.45.1 million annualized) change in our pre-tax operating cash flow. The average price we received for our natural gas production, including the effect of derivatives, during the first ninesix months of 20182019 was $2.35$2.18 compared to $2.50$2.40 for the first ninesix months of 2017.2018. Based on our first ninesix months of 20182019 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $225,000$224,000 per month ($2.7 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 $398,000$386,000 per month ($4.84.6 million annualized) change in our pre-tax operating cash flow. In the first ninesix months of 2018,2019, our average oil price per barrel received, including the effect of derivatives, was $56.40$58.16 compared with an average oil price, including the effect of derivatives, of $47.62$55.76 in the first ninesix months of 20172018 and our first ninesix months of 20182019 average NGLs price per barrel received, including the effect of derivatives was $23.03$14.11 compared with an average NGLs price per barrel of $17.05$21.65 in the first ninesix months of 2017.2018.


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 SeptemberJune 30, 2018,2019, the 12-month average unescalated prices were $63.43$61.39 per barrel of oil, $38.69$32.38 per barrel of NGLs, and $2.91$3.02 per Mcf of natural gas, and then are adjusted for price differentials. We did not take a write down in the first ninesix months of 2018.2019.



We anticipate a non-cash ceiling test write-down in the third quarter of 2019. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at SeptemberJune 30, 2018,2019, and only adjust the 12-month average price to an estimated fourththird quarter ending average (holding October 2018July 2019 prices constant for the remaining two months of the fourththird quarter of 2018)2019), our forward looking expectation is that we will notwould recognize an impairment of $107 million pre-tax in the fourththird quarter of 2018. But commodity prices (and other factors) remain volatile and they could negatively affect2019. The estimated third-quarter 2019 impairment would be partially the result of a decrease in our proved undeveloped reserves of approximately 16%. This decrease would be primarily due to certain locations no longer being economical under the adjusted 12-month average price resultingfor the third quarter. As a result, we may eliminate those locations from our future development plans. Given the uncertainty associated with the factors used in calculating our estimate of both our future period ceiling test write-down and the potential for adecrease in our undeveloped reserves, these estimates should not necessarily be construed as indicative of our future impairment.development plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination.


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 wereare drilling horizontal or directional wells for oil and NGLs. The continuous fluctuations in commodity prices for oil and natural gas changes the demand for drilling rigs. These factors ultimately affect the demand and mix of the type of drilling rigs used by our customers. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates. For the first ninesix months of 2018,2019, our average dayrate was $17,327$18,412 per day compared to $16,120$17,184 per day for the first ninesix months of 2017.2018. The average number of our drilling rigs used in the first ninesix months of 20182019 was 32.730.0 drilling rigs compared with 29.731.9 drilling rigs in the first ninesix months of 2017.2018. Based on the average utilization of our drilling rigs during the first ninesix months of 2018,2019, a $100 per day change in dayrates has a $3,270$3,000 per day ($1.21.1 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 income statements, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $18.0$14.8 million and $9.6$10.6 million for the first ninesix months of 20182019 and 2017,2018, respectively, from our contract drilling segment and eliminated the associated operating expense of $15.5$13.1 million and $8.6$9.3 million during the first ninesix months
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of 2019 and 2017,2018, respectively, yielding $2.4$1.7 million and $1.0$1.3 million during the first ninesix months of 20182019 and 2017,2018, respectively, as a reduction to the carrying value of our oil and natural gas properties.


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, 1412 processing plants, 2221 gathering systems, and approximately 1,4701,500 miles of pipeline. It operates in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. Besides serving third parties, this segment also enhances our ability to gather and market our own natural gas and NGLs and serving as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first ninesix months of 20182019 and 2017,2018, our mid-stream operations purchased $59.8$24.8 million and $43.2$36.5 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $5.2$3.6 million and $4.9$3.4 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 393,414457,859 Mcf per day in the first ninesix months of 20182019 compared to 385,846382,005 Mcf per day in the first ninesix months of 2017.2018. It processed an average of 157,313163,725 Mcf per day in the first ninesix months of 20182019 compared to 133,986155,799 Mcf per day in the first ninesix months of 2017.2018. The NGLs sold was 651,979681,070 gallons per day in the first ninesix months of 20182019 compared to 518,054627,305 gallons per day in the first ninesix months of 2017.2018. Gas gathered volumes per day in the first ninesix months of 20182019 increased 2%20% compared to the first ninesix months of 20172018 primarily due to connecting additional wells to our CashionPennsylvania and HemphillOklahoma facilities. Gas processed volumes for the first ninesix months of 20182019 increased 17%5% over the first ninesix months of 20172018 due to connecting new wells mainly at theour Cashion and Hemphill processing facilities.facility. NGLs sold increased 26%9% over the comparative period due to higherincreased volume available to process at our plantsprocessing facilities from additional well connections along with operating in higher recovery mode.

At-the-Market (ATM) Common Stock Program

On May 2, 2018, we terminated the Distribution Agreement dated April 4, 2017, as amended (the Distribution Agreement), between the company and Raymond James & Associates, Inc. (the Sales Agent). The Distribution Agreement was terminable at will on written notification by the company with no penalty. Under the Distribution Agreement, the company was entitled to issue and sell, from time to time, through or to the Sales Agent shares of its common stock, having an aggregate offering price of up to $100.0 million in an “at-the-market” offering program. As of the date of termination, the company sold 787,547 shares of its Common Stock under the Distribution Agreement. As a result of the termination, there will be no more sales of the our common stock under the Distribution Agreement.


Our Credit Agreements and Senior Subordinated Notes


Unit Credit Agreement. On October 18, 2018, we signed the fifth amendment to the UnitOur Senior Credit Agreement (Unit credit agreement originallyagreement) is scheduled to mature on April 10, 2020 (Fifth Amendment). The Fifth Amendment amends our existing credit agreement entered into between the Company and certain lenders on September 13, 2011, as amended September 12, 2012, as further amended April 10, 2015, as further amended on April 8, 2016, as further amended on April 2, 2018, attached as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 15, 2011, September 11, 2012, April 13, 2015, April 8, 2016, and April 6, 2018, respectively, and the Company’s Current Report on Form 8-K/A filed on April 13, 2016, and each incorporated by reference herein.

The Fifth Amendment, among other things, (i) extends the term of the Unit credit agreement to October 18, 2023, subject to certain conditions; (ii) reduces the pricing for borrowing and non-use fees; and (iii) eliminates the requirement2023. Under that the company maintain a senior indebtedness to consolidated EBITDA ratio. The total commitment of credit and the borrowing base both remain unchanged at $425.0 million.

Under the Unit 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 the maximum credit agreement.agreement amount of $1.0 billion. Our elected commitment amount is $425.0 million. Our borrowing base is $425.0 million. We are currently charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the total borrowing base. Total amendment fees of $3.3 million in origination, agency, syndication, and other related fees are being amortized over the life of the Unit credit agreement. Under the Unit credit agreement, we have pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties.

On April 2, 2018, we signed the fourth amendment to the Unit credit agreement. The Fourth Amendment provided, among other things, for a reduction of the maximum credit amount from $875.0 million to $425.0 million, a reduction in the borrowing base from $475.0 million to $425.0 million, a reduction in the total commitment amount from $475.0 million to $425.0 million; and the full release of Superior and its subsidiaries as a borrower and co-obligor under the Unit credit agreement. Under the amendment once the sale of the interest in Superior was completed, we were required to us part of the proceeds to pay down the Unit credit agreement. The Superior sale closed on April 3, 2018 and the pay down was made that day.


On May 2, 2018, as contemplated under the Fourth Amendment, we entered into a Pledge Agreement with BOKF, NA (dba Bank of Oklahoma), as administrative agent for theto benefit of the secured parties, under which we grantedgranting a security interest in the limited liability membership interests and other equity interests we own in Superior (which as of the date of this report is 50% of the aggregate outstanding equity interests of Superior) as additional collateral for our obligations under the Unit credit agreement.



The current lenders under our Unit credit agreement and their respective participation interests are:
Lender
Participation

Interest
BOK (BOKF, NA, dba Bank of Oklahoma)17.060%
BBVA Compass Bank17.060%
BMO Harris Financing, Inc.15.294%
Bank of America, N.A.15.294%
Comerica Bank8.235%
Toronto Dominion Bank, New York Branch8.235%
Canadian Imperial Bank of Commerce8.235%
Arvest Bank3.529%
Branch Banking & Trust3.529%
IBERIABANK3.529%
100.000%


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The borrowing base amount amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year year–is based on a percentage of the discounted future value of our oil and natural gas reserves. 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 Unit credit agreement.


At our election, any part of the outstanding debt under the Unit credit agreement couldcan be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base for the term plus 1.50% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the Unit credit agreement that cannot bebut in no event less than LIBOR plus 1.00% plus a margin.margin. The credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index. Interest is payable at the end of each month or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty. At SeptemberJune 30, 2018,2019, we did not have anyhad $103.5 million outstanding borrowings. The outstanding balance was paid down on April 3, 2018.under the Unit credit agreement.


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


The Unit 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;
•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; and
•investments in Unrestricted Subsidiaries (as defined in excess ofthe Unit credit agreement) over $200.0 million.


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


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

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


As of SeptemberJune 30, 2018,2019, we were in compliance with the Unit credit agreementthese covenants.


Superior Credit Agreement. On May 10, 2018, Superior, a limited liability company equally owned between the Companycompany and SP Investor Holdings, LLC, 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. The amounts borrowed under the

Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) third day LIBOR plus 1.00%) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems. The credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index.


Superior is currently charged a commitment fee of 0.375% on the amount available but not borrowed which varies based on the amount borrowed as a percentage of the total borrowing base. Superior paid $1.7 million in origination, agency, syndication, and other related fees. These fees are being amortized over the life of the Superior credit agreement.


The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. Additionally, the Superior credit agreement contains a number of customary covenants that, among
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other things, restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, enter into sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, enter into hedging arrangements, and acquire or dispose of assets. As of SeptemberJune 30, 2018,2019, Superior was in compliance with the Superior credit agreement covenants.
 
The borrowings the Superior credit agreement will be used tofund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior. As of June 30, 2019, we had $7.5 million outstanding borrowings under the Superior credit agreement.


On June 27, 2018, Superior and the lenders amended the Superior credit agreement to revise certain definitions in the agreement.


Superior's credit agreement is not guaranteed by Unit.


The current lenders under the Superior credit agreement and their respective participation interests are:
Lender
Participation

Interest
BOK (BOKF, NA, dba Bank of Oklahoma)17.50%
Compass Bank17.50%
BMO Harris Financing, Inc.13.75%
Toronto Dominion (New York), LLC13.75%
Bank of America, N.A.10.00%
Branch Banking and Trust Company10.00%
Comerica Bank10.00%
Canadian Imperial Bank of Commerce7.50%
100.00%


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


The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for issuing the Notes. The Guarantors are most of our direct and indirect subsidiaries, but excluding Superior. 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 significant 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. Effective April 3, 2018, Superior is no longer a Guarantor of the Notes. AnyExcluding Superior, any of our other 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, subjectunless the Company has exercised its right to certain conditions,redeem all of the Notes, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. As of May 15, 2019, we may redeem the Notes at a redemption price equal to 100% of the principal amount of the Notes plus accrued and unpaid interest on 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 SeptemberJune 30, 2018.2019.

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We may from time to time seek to retire or purchase our outstanding Note debt through cash purchases and/or exchanges for securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

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 7363 gross wells (21.06(17.41 net wells) in the first ninesix months of 20182019 compared to 4334 gross wells (15.10(12.40 net wells) in the first ninesix months of 2017.2018.


At June 30, 2019 we had commitments to purchase approximately $0.5 million for casing over the next year. Capital expenditures for oil and gas properties on the full cost method for the first ninesix months of 20182019 by this segment, excluding $0.8$3.3 million for acquisitions and a $8.5$3.7 million increase in the ARO liability, totaled $195.5 million. Capital expenditures for the first six months of 2018, excluding $1.0 million for acquisitions and a $7.9 million reduction in the ARO liability, totaled $259.4 million. Capital expenditures for the first nine months of 2017, excluding $56.4 million for acquisitions and a $2.8 million reduction in the ARO liability, totaled $143.7$157.7 million.


We anticipate participating in drilling approximately 9585 to 10595 gross wells in 20182019 and our total estimated capital expenditures (excluding a reduction in ARO liability and any possible acquisitions) for this segment areis approximately $333.0 million.$265.0 million (slightly lower than the original $271.0 million to $315.0 million range) due to lower commodity prices. Whether we can drill the full number of wells planned depends on several factors, many of which are beyond our control, including the availability of drilling rigs, availability of pressure pumping services, prices for oil, NGLs, and natural gas, demand for oil, NGLs, and natural gas, the cost to drill wells, the weather, and the efforts of outside industry partners.


Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. During the first quarter of 2018, we were awarded a term contract to build our 11th BOSS drilling rig. Construction has been completedrig which was constructed and the drilling rig was placed into service in mid-July.the second quarter of 2018. During the second quarter and third quarter of 2018, we were awarded a term contractscontract to build our 12th BOSS drilling rig.

During the first quarter of 2019, we completed construction and placed into service our 12th and 13th BOSS drilling rigs. One was delivered to an existing third party operator in Wyoming. Two additional BOSS drilling rigs under contract with the same customer were also extended. The other BOSS drilling rig was delivered to a new customer in the Permian Basin. This was following an early termination by the original third party operator prior to the drilling rig’s completion.

During the second quarter of 2019, we were awarded a term contract to build our 14th BOSS drilling rig. Construction is in progresshas started and the drilling rigs willrig is expected to be placed into service with a third party operator in the first quarterfourth quarter. Two existing BOSS drilling rig contracts working for the same operator were also extended at the time of 2019.the new BOSS drilling rig award.


Our estimated 20182019 capital expenditures for this segment areis approximately $73.0 million.$45.0 million (the midpoint of the original $30.0 million to $65.0 million range) due to the construction of our 14th BOSS drilling rig. At SeptemberJune 30, 2018,2019, we had commitments to purchase approximately $10.1$1.1 million for drilling equipment over the next year. We have spent $46.5 million for capital expenditures during the first nine months of 2018, compared to $30.0$24.9 million for capital expenditures during the first ninesix months of 2017.2019, compared to $23.0 million for capital expenditures during the first six months of 2018.


Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. In the Appalachian region at the Pittsburgh Mills gathering system, the average gathered volume for the thirdsecond quarter of 2018 increased to2019 was approximately 142.6206.4 MMcf per day afterday. In the first quarter of 2019, we added seven new infill wells latewhich accounted for the significant increase in the second quarter. All the new infill wells are currently online and flowing gas. We are completing construction of the new pipeline to connect the next scheduled well pad to our system. Construction of this pipeline is operationally complete and the improvements to the compressor station are expected to be completed early in the fourth quarter. We anticipate receiving production from this pad earlygathered volume in the first quarter. In the second quarter of 2019.

At2019, the Hemphill Texas system, average total throughput volume increased to 74.1 MMcf per day for the third quarter of 2018 and total production of NGLs increased to approximately 316,110 gallons per day. During the third quarter, we connected one new wellfrom these wells is declining as evidenced in the Buffalo Wallow area. This new well along with increased production from recently drilledlower volume as of June 2019. These wells in this area contributed to our increased throughput volume.are all long lateral wells. The increased liquid production was due to operating in ethane recovery mode. Unit Petroleum continues to operate a rig in the Buffalo Wallow area and we anticipate connecting additional wells to this system in the 4th quarter. Additionally, we have completed a construction project that increased our compression capacity at the Buffalo WallowKissick compressor station facilities located on the south end of the system have been upgraded and are able to accommodate expected additional volumes.  handle the increased volume from these new wells.



At the Cashion processing facility in central Oklahoma, total throughput volume for the second quarter of 20182019 averaged approximately 47.556.7 MMcf per day and total production of NGLsnatural gas liquids increased to approximately 233,700273,075 gallons per day. ThisWe are continuing to connect new wells to this system is operating at full processing capacity andfrom several third party producers. In 2019, we arehave connected 16 new wells to this system from several third party producers who continue to be active in the processarea. During the second quarter, we completed the addition of adding additional capacity on this system. We have begun the relocation of anew 60 MMcf per day Reeding processing facility on the Cashion system. This 60 MMcf per day processing
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plant was relocated from our Bellmon facility to the Cashion system. This $20.0 million plant expansion/relocation projectarea and is underway and will increasenow fully operational. The addition of this new processing facility increases our total processing capacity on the Cashion system to approximately 105 MMcf per day. This project is expected to be completed and operational

At the Hemphill processing facility located in the firstTexas panhandle, average total throughput volume for the second quarter of 2019. We2019 was 72.9 MMcf per day and total production of natural gas liquids was 288,762 gallons per day during this same period. Since the first of this year, we have connected eightsix new wells to this systemthe Hemphill system. The six new wells connected in the third quarter of 2018 and we2019 are continuing to connect additionalUnit Petroleum wells. There are no Unit Petroleum wells from a third party producer who is activecurrently being drilled in this area.

At the Segno gathering facility in Southeast Texas, gathered volume for the third quarter of 2018 averaged approximately 83.1 MMcf per day. At this facility, the existing gathering and dehydration capacity will allow us to gather up to 120 MMcf per day. In the third quarter of 2018, we added one new well to this system. Unit Petroleum is actively drilling in the Segno area, as well as, reworking and recompleting existing wells that are connected to our system which will continue to add additional volume.

On April 3, 2018, the company completed the sale of 50% of the ownership interests in Superior to SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager, for cash consideration of $300.0 million.


During the first ninesix months of 2018,2019, our mid-stream segment incurred $29.0$32.6 million in capital expenditures as compared to $10.1$13.8 million in the first ninesix months of 2017. For 2018, our2018. Our estimated 2019 capital expenditures arefor this segment is approximately $50.0 million.$45.0 million (slightly higher than the original $35.0 million to $42.0 million range) due to the purchase of previously leased assets.


Contractual Commitments


At SeptemberJune 30, 2018,2019, we had certain contractual obligations including:
 Payments Due by Period
 TotalLess
Than
1 Year		2-3
Years		4-5
Years		After
5 Years
 (In thousands)
Long-term debt (1)
$862,480 $47,945 $697,400 $117,135 $— 
Operating leases under ASC 840 (2)
507 507 — — — 
Operating leases under ASC 842 (3)
8,075 4,519 3,297 195 64 
Finance lease interest and maintenance (4)
3,620 2,087 1,533 — — 
Drilling rig components and casing (5)
1,584 1,584 — — — 
Total contractual obligations$876,266 $56,642 $702,230 $117,330 $64 
  Payments Due by Period
  Total 
Less
Than
1 Year
 
2-3
Years
 
4-5
Years
 
After
5 Years
  (In thousands)
Long-term debt (1)
 $762,906
 $43,063
 $719,843
 $—
 $—
Operating leases (2)
 7,967
 5,144
 2,798
 25
 —
Capital lease interest and maintenance(3)
 5,357
 2,234
 3,123
 —
 —
Drill pipe, drilling components, and equipment purchases (4)
 10,064
 10,064
 —
 —
 —
Total contractual obligations $786,294
 $60,505
 $725,764
 $25
 $—
_______________________
_______________________
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 June 30, 2019 interest rates of 6.625% for the Notes and 4.2% for our Unit credit agreement and 6.5% for our Superior credit agreement. At June 30, 2019, our Unit credit agreement and our Superior credit agreement had maturity dates of October 18, 2023 and May 10, 2023, respectively. The outstanding Unit and Superior credit agreements balance were $103.5 million and $7.5 million, respectively, as of June 30, 2019.
(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, 2018 interest rates of 6.625% for the Notes. At September 30, 2018, our credit agreement had a maturity date of April 10, 2020. The outstanding credit facility balance was paid down on April 3, 2018 and as of September 30, 2018, we did not have any outstanding borrowings.


(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.

2.We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; and Pinedale, Wyoming under the terms of operating leases expiring through March 2020. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.
(3)Maintenance and interest payments are included in our capital lease agreements. The capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining are $4.6 million and $0.8 million, respectively.


(4)We have committed to pay $10.1 million for drilling rig components, drill pipe, and related equipment over the next year.

3.We lease certain office space, land and equipment, including pipeline equipment and office equipment under the terms of operating leases under ASC 842 expiring through March 2032.

4.Maintenance and interest payments are included in our finance lease agreements. The finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining are $3.2 million and $0.4 million, respectively.

5.We have committed to pay $1.6 million for drilling rig components and casing over the next year.

During the second quarter of 2018, as part of the Superior transaction, we entered into a contractual obligation that commits us to spend $150.0 million for drillingto drill wells in the Granite Wash/Buffalo Wallow area over the next three years starting January 1, 2019. This amount is already included in our future drilling plan.plans. For each dollar of the $150.0 million that we do not spend (over the three year period), we would forgo receiving $0.58 of future distributions from our 50% ownership interest in our consolidated mid-stream subsidiary. IfAt June 30, 2019, if we elected not to drill or spend any additional money in the designated area over the three year period,before December 31, 2021, the maximum amount we could forgo from distributions would be $87.0$74.0 million. Total spent towards the $150.0 million as of June 30, 2019 was $22.4 million.





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At SeptemberJune 30, 2018,2019, we also had the following commitments and contingencies that could create, increase, or accelerate our liabilities:
 Estimated Amount of Commitment Expiration Per Period
Other CommitmentsTotal
Accrued		Less
Than 1
Year		2-3
Years		4-5
Years		After 5
Years
 (In thousands)
Deferred compensation plan (1)
$6,002 UnknownUnknownUnknownUnknown
Separation benefit plans (2)
$9,749 $1,083 UnknownUnknownUnknown
Asset retirement liability (3)
$67,433 $1,784 $40,376 $3,837 $21,436 
Gas balancing liability (4)
$3,372 UnknownUnknownUnknownUnknown
Repurchase obligations (5)
$— $— $— $— $— 
Workers’ compensation liability (6)
$12,118 $4,050 $2,438 $1,109 $4,521 
Finance lease obligations (7)
$9,400 $4,081 $5,319 $— $— 
Contract liability (8)
$8,513 $2,889 $4,960 $638 $26 
  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)
 $5,623
 Unknown
 Unknown
 Unknown
 Unknown
Separation benefit plans (2)
 $8,135
 $966
 Unknown
 Unknown
 Unknown
Asset retirement liability (3)
 $62,727
 $1,451
 $36,308
 $3,747
 $21,221
Gas balancing liability (4)
 $3,283
 Unknown
 Unknown
 Unknown
 Unknown
Repurchase obligations (5)
 $—
 Unknown
 Unknown
 Unknown
 Unknown
Workers’ compensation liability (6)
 $12,832
 $4,897
 $2,501
 $1,067
 $4,367
Capital leases obligations (7)
 $12,355
 $3,961
 $8,394
 $—
 $—
Contract liability (8)
 $10,605
 $2,875
 $5,654
 $2,076
 $—
_______________________ 
(1)We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death, or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets, at the time of deferral.

1.We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death, or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets, at the time of deferral.
(2)Effective January 1, 1997, we adopted a separation benefit plan (“Separation Plan”). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Currently there are no participants in the Senior Plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (“Special Plan”). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company.


(3)When a well is drilled or acquired, under ASC 410 “Accounting for Asset Retirement Obligations,” we record the discounted fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).

2.Effective January 1, 1997, we adopted a separation benefit plan (“Separation Plan”). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Currently there are no participants in the Senior Plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (“Special Plan”). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company.
(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 made repurchases of approximately $1,700 and $2,900 in the first nine months of 2018 and 2017, respectively.

3.When a well is drilled or acquired, under ASC 410 “Accounting for Asset Retirement Obligations,” we record the discounted fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).
(6)We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment.


(7)The amount includes commitments under capital lease arrangements for compressors in Superior.

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.
(8)We have recorded a liability related to the timing of revenue recognized on certain demand fees for Superior.


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 six months of 2018. The partnerships were terminated during the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest.

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 finance lease arrangements for compressors in Superior.

8.We have recorded a liability related to the timing of revenue recognized on certain demand fees for Superior.

Derivative Activities


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


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Commodity Derivatives. Our commodity derivatives are intended to reduce our exposure to price volatility and manage price risks. Our decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our view of current and future market conditions. At SeptemberJune 30, 2018,2019, based on our thirdsecond quarter 20182019 average daily production, the approximated percentages of our production under derivative contracts are as follows:
2019 
Q3Q4
Daily oil production51 %51 %
Daily natural gas production55 %46 %
  2018 2019
  Q4  
Daily oil production 80% 53%
Daily natural gas production 28% 13%


With respect to the commodities subject to derivative contracts, those contracts serve to limit the risk of adverse downward price movements. However, they also limit increases in future revenues that would otherwise result from price movements above the contracted prices.


The use of derivative transactions carries with it the risk that the counterparties may not be able to meet their financial obligations under the transactions. Based on our SeptemberJune 30, 20182019 evaluation, we believe the risk of non-performance by our counterparties is not material. At SeptemberJune 30, 2018,2019, the fair values of the net assets (liabilities) we had with each of the counterparties to our commodity derivative transactions are as follows:
June 30, 2019
(In millions)
Bank of Montreal$6.1 
Bank of America2.1 
Total net assets$8.2 
  September 30, 2018
  (In millions)
Canadian Imperial Bank of Commerce $—
Bank of America (2.2)
Bank of Montreal (12.4)
Total liabilities $(14.6)

If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets. At SeptemberJune 30, 2018, we recorded the fair value of our commodity derivatives on our balance sheet as current and non-current derivative liabilities of $13.1 million and $1.5 million, respectively. At December 31, 2017,2019, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $0.7$8.5 million and currentnon-current derivative liabilities of $7.8$0.3 million. At December 31, 2018, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $12.9 million and non-current derivative liabilities of $0.3 million.


For our economic hedges any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Income Statements.Statements of Operations. These gains (losses) at SeptemberJune 30 are as follows:
Three Months EndedSix Months Ended
June 30,June 30,
2019 2018 2019 2018 
 (In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $2,658, ($6,855), $5,314 and ($8,928), respectively$7,927 $(14,461)$995 $(21,223)
$7,927 $(14,461)$995 $(21,223)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2018 2017 2018 2017
  (In thousands)
Gain (loss) on derivatives:        
Gain (loss) on derivatives, included are amounts settled during the period of ($9,112), $840, ($18,040) and ($729), respectively $(4,385) $(2,614) $(25,608) $21,019
  $(4,385) $(2,614) $(25,608) $21,019


Stock and Incentive Compensation


During the first ninesix months of 2019, we granted awards covering 1,424,027 shares of restricted stock. These awards had an estimated fair value as of their grant date of $22.6 million. Compensation expense will be recognized over the three year vesting periods, and during the six months of 2019, we recognized $3.4 million in compensation expense and capitalized $0.6 million for these awards. During the first six months of 2019, we recognized compensation expense of $8.5 million for all of our restricted stock and capitalized $1.3 million of compensation cost for oil and natural gas properties.

During the first six months of 2018, we granted awards covering 1,250,880 shares of restricted stock. These awards had an estimated fair value as of their grant date of $24.4 million. Compensation expense will be recognized over the three year vesting periods, and during the ninesix months of 2018, we recognized $6.6$3.7 million in compensation expense and capitalized $1.0 $0.6
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million for these awards. During the first ninesix months of 2018, we recognized compensation expense of $13.6$9.5 million for all of our restricted stock and stock options and capitalized $1.6$1.0 million of compensation cost for oil and natural gas properties.

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.


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 ninesix months of 2018, and 2017, the total we received for all of these fees was $0.1 million in each period.million. Our proportionate share of assets, liabilities, and net income relating to the oil and natural gas partnerships is included in our unaudited condensed consolidated financial statements.The partnerships were terminated during the second quarter of 2019 with an effective date of January 1, 2019.


New Accounting Pronouncements


Measurement of Credit Losses on Financial Instruments (Topic 326). The FASB issued ASU 2016-13 which replaces current methods for evaluating impairment of financial instruments not measured at fair value, including trade accounts receivable and certain debt securities, with a current expected credit loss model. The amendment will be effective for reporting periods after December 15, 2019. We are evaluating the impact this will have on our financial statements by reviewing our accounts receivable accounts and our historic credit losses.

Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were removed or modified and other disclosures were added. The amendment will be effective for reporting periods beginning after December 15, 2019. Early adoption is permitted. Also it is permitted to early adopt any removed or modified disclosure and delay adoption of the additional disclosures until their effective date. This amendment will not have a material impact on our financial statements.


Compensation—Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting. The FASB issued ASU 2018-07, to improve financial reporting for nonemployee share-based payments. The amendment expands the scope of Topic 718, Compensation—Stock Compensation to include share-based payments issued to nonemployees for goods or services. The amendment will be effective for years beginning after December 15, 2019, and interim periods within those years. This amendment will not have a material impact on our financial statements.

Income Taxes - Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118. In March 2018, the FASB issued ASU 2018-05 which updates the FASB’s Accounting Standards Codification to reflect the guidance in SAB 118, which adds Section EE, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” to SAB Topic 5, “Miscellaneous Accounting.” SAB 118 also provides guidance on applying ASC 740, Income Taxes, if the accounting for certain income tax effects of the Tax Cuts and Jobs Act of 2017 is incomplete when the financial statements are issued for a reporting period.

Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This amendment will not have a material impact on our financial statements.


Leases. Adopted Standards

Compensation—Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting. The FASB has issued several accounting standards updates and amendments relatedASU 2018-07, to leases in the past two years, which are codified withinimprove financial reporting for nonemployee share-based payments. The amendment expands Topic 842. For public companies, these are718, Compensation—Stock Compensation to include share-based payments issued to nonemployees for goods or services. The amendment is effective for annual periodsyears beginning after December 15, 2018, and interim periods within those annual periods. The standard requires lessees to recognize at the commencement date of a lease a lease liability, which represents the lessee's obligation to make lease payments arising from the lease, measured on a discounted basis; and a right-of-use asset, which represents the lessee's right to use a specified asset for the lease term. Other recently issued amendments to Topic 842years. This amendment did not have provided clarifying guidance regarding land easements, an

additional modified retrospective transition method, and added several practical expedients to apply Topic 842 for both lessees and lessors. The standard will not apply to leases of mineral rights.

We have an implementation team working through the provisions of the new guidance including a review of different types of contracts to document our lease portfolio and assess the impact on our accounting, disclosures, processes, internal control over financial reporting, and the election of certain practical expedients. Our evaluation of the impact of the new guidance on our financial statements is on-going.statements.


We have made certain accounting policy decisions including that we plan to adopt the short-term lease recognition exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization threshold. Our transition will utilizeadopted ASC 842 on January 1, 2019, using the modified retrospective approach to adopting the new standard, and will be applied at the beginning of the period adopted (January 1, 2019) in accordance with ASU 2018-11. We expect to elect the transition practical expedient, which allows us to not evaluate land easements that existed prior to January 1, 2019,method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. We expectResults for certain lessee asset classes to elect the practical expedient and not separate lease and nonlease components. For these asset classes, we will account for the agreements as a single lease component.

We expect for certain lessor asset classes to elect the practical expedient and not separate lease and nonlease components and determine the appropriate accounting based on the predominate component of the contract. The assessment of predominance is ongoing.

We anticipate a material impact to the balance sheet across segments as we recognize Right of Use assets and liabilities but no material impact to the income statement (from the lessee's perspective). The assessment of the dollar value impact of adoption is on-going.

Adopted Standards

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The FASB issued ASU 2018-02, an amendment which provides financial statement preparers with an option to reclassify stranded tax effects within AOCI to retained earnings caused by the Tax Cuts and Jobs Act of 2017. The amendment is effective for fiscal yearsreporting periods beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. Organizations should apply the proposed amendments either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Cuts and Jobs Act is recognized. We adopted this amendment early and it had no material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and now we are using 24.5%. The change is reflected in our Unaudited Condensed Consolidated Statements of Comprehensive Income and in Note 14 - Equity.

Revenue from Contracts with Customers. Effective January 1, 2018, we adopted ASC 606. This new revenue standard provides for a five-step analysis of transactions to determine when and how revenue is to be recognized. The guidance in this update supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. Under the standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five step method outlined in the ASU to all of our revenue streams in the scope of ASC 606 and elected the modified retrospective approach method. Under that approach the cumulative effect on adoption is recognized as an adjustment to opening retained earnings at January 1, 2018. Only our mid-stream segment was affected. This adjustment related to the timing of revenue on certain demand fees. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative2019, are presented under Topic 842, while prior periods haveare not been adjusted and continue to be reported under ASC 605.the accounting standards in effect for those periods.


The additional disclosures required by ASC 606842 have been included in Note 212 – Revenue from Contracts with Customers.Leases.

Our internal control framework did not materially change as a result
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Table of this standard, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard, we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.Contents


Results of Operations
Quarter Ended SeptemberJune 30, 20182019 versus Quarter Ended SeptemberJune 30, 20172018
Provided below is a comparison of selected operating and financial data:
 Quarter Ended June 30,
Percent
Change (1)
 2019 2018 
(In thousands unless otherwise specified) 
Total revenue$165,146 $203,303 (19)%
Net income (loss)$(8,017)$8,150 (198)%
Net income attributable to non-controlling interest$492 $2,362 (79)%
Net income (loss) attributable to Unit Corporation$(8,509)$5,788 NM  
Oil and Natural Gas:
Revenue$77,815 $102,318 (24)%
Operating costs excluding depreciation, depletion, and amortization$36,242 $32,418 12 %
Depreciation, depletion, and amortization$38,751 $31,554 23 %
Average oil price received (Bbl)$59.94 $56.46 6 %
Average NGLs price received (Bbl)$12.52 $22.18 (44)%
Average natural gas price received (Mcf)$1.86 $2.18 (15)%
Oil production (Bbl)726,000 693,000 5 %
NGLs production (Bbl)1,210,000 1,230,000 (2)%
Natural gas production (Mcf)13,288,000 13,738,000 (3)%
Depreciation, depletion, and amortization rate (Boe)$8.94 $7.14 25 %
Contract Drilling:
Revenue$43,037 $46,926 (8)%
Operating costs excluding depreciation$29,308 $31,894 (8)%
Depreciation$13,504 $13,726 (2)%
Percentage of revenue from daywork contracts100 %100 %— %
Average number of drilling rigs in use28.6 32.2 (11)%
Average dayrate on daywork contracts$18,491 $17,330 7 %
Mid-Stream:
Revenue$44,294 $54,059 (18)%
Operating costs excluding depreciation and amortization$32,491 $39,703 (18)%
Depreciation and amortization$12,102 $11,175 8 %
Gas gathered—Mcf/day465,714 391,047 19 %
Gas processed—Mcf/day165,682 160,506 3 %
Gas liquids sold—gallons/day711,192 676,503 5 %
Corporate and Other:
General and administrative expense$10,064 $8,712 16 %
Other depreciation$1,935 $1,918 1 %
Gain on disposition of assets$422 $161 162 %
Other income (expense):
Interest income$3 $411 (99)%
Interest expense, net$(8,998)$(8,140)11 %
Gain (loss) on derivatives$7,927 $(14,461)155 %
Other$6 $5 20 %
Income tax (benefit) expense$(1,874)$2,029 (192)%
Average long-term debt outstanding$731,037 $646,760 13 %
Average interest rate6.5 %6.7 %(3)%
  Quarter Ended September 30, 
Percent
Change (1)
  2018 2017 
  (In thousands unless otherwise specified)  
Total revenue $220,058
 $188,488
 17 %
Net income $21,123
 $3,705
 NM
Net income attributable to non-controlling interest $2,224
 $—
 — %
Net income attributable to Unit Corporation $18,899
 $3,705
 NM
       
Oil and Natural Gas:      
Revenue $111,623
 $85,470
 31 %
Operating costs excluding depreciation, depletion, and amortization $32,139
 $33,911
 (5)%
Depreciation, depletion, and amortization $35,460
 $26,460
 34 %
       
Average oil price received (Bbl) $57.72
 $47.29
 22 %
Average NGLs price received (Bbl) $25.66
 $18.35
 40 %
Average natural gas price received (Mcf) $2.27
 $2.36
 (4)%
Oil production (Bbl) 692,000
 633,000
 9 %
NGLs production (Bbl) 1,278,000
 1,243,000
 3 %
Natural gas production (Mcf) 14,336,000
 13,085,000
 10 %
Depreciation, depletion, and amortization rate (Boe) $7.56
 $6.18
 22 %
       
Contract Drilling:      
Revenue $50,612
 $51,619
 (2)%
Operating costs excluding depreciation $32,032
 $34,747
 (8)%
Depreciation $14,889
 $15,280
 (3)%
       
Percentage of revenue from daywork contracts 100% 100% — %
Average number of drilling rigs in use 34.2
 34.6
 (1)%
Average dayrate on daywork contracts $17,589
 $16,454
 7 %
       
Mid-Stream:      
Revenue $57,823
 $51,399
 12 %
Operating costs excluding depreciation and amortization $43,134
 $38,116
 13 %
Depreciation and amortization $11,265
 $10,880
 4 %
       
Gas gathered—Mcf/day 415,862
 383,787
 8 %
Gas processed—Mcf/day 160,294
 140,246
 14 %
Gas liquids sold—gallons/day 700,523
 530,028
 32 %
       
Corporate and other:      
General and administrative expense $9,278
 $9,235
 — %
Other depreciation $1,923
 $1,913
 1 %
Gain on disposition of assets $253
 $81
 NM
Other income (expense):      
Interest income $385
 $—
 — %
Interest expense, net $(8,330) $(9,944) (16)%
Loss on derivatives $(4,385) $(2,614) 68 %
Other $6
 $5
 20 %
Income tax expense $6,744
 $1,769
 NM
Average long-term debt outstanding $635,870
 $804,617
 (21)%
Average interest rate 6.7% 6.0% 12 %
_________________________
_________________________
1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
(1)NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

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Oil and Natural Gas


Oil and natural gas revenues increased $26.2decreased $24.5 million or 31%24% in the thirdsecond quarter of 20182019 as compared to the thirdsecond quarter of 20172018 primarily due to higher oillower unhedged NGLs and NGLsnatural gas prices and higherfrom lower NGLs and natural gas production volumes partially offset by lower gas prices.volumes. In the thirdsecond quarter of 2018,2019, as compared to the thirdsecond quarter of 2017,2018, oil production increased 9%5%, natural gas production increased 10%decreased 3%, and NGLs production increased 3%decreased 2%. AverageIncluding derivatives settled, average oil prices increased 22%6% to $57.72$59.94 per barrel, average natural gas prices decreased 4%15% to $2.27$1.86 per Mcf, and NGLs prices increased 40%decreased 44% to $25.66$12.52 per barrel.


Oil and natural gas operating costs decreased $1.8increased $3.8 million or 5%12% between the comparative thirdsecond quarters of 2019 and 2018 and 2017primarily due to the impact of the ASC 606 Revenue Recognition classification of certain deducts partially offset by higher gross production taxes.lease operating expenses (LOE) and salt water disposal expenses.


Depreciation, depletion, and amortization (DD&A) increased $9.0$7.2 million or 34%23% due primarily to a 22%25% increase in the DD&A rate andpartially offset by an 7% increase1% decrease in equivalent production. The increase in our DD&A rate in the thirdsecond quarter of 20182019 compared to the thirdsecond quarter of 20172018 resulted primarily from the cost of wells drilled in the last threesix months of 20172018 and the first ninesix months of 2018.2019.


Contract Drilling


Drilling revenues decreased $1.0$3.9 million or 2%8% in the thirdsecond quarter of 20182019 versus the thirdsecond quarter of 2017.2018. The decrease was due primarily to an 1%11% decrease in the average number of drilling rigs in use and an increase in eliminations with an increase percentage of our drilling rigs being used by our oil and gas segment partially offset by a 7% increase in the average dayrate. Average drilling rig utilization decreased from 34.632.2 drilling rigs in the thirdsecond quarter of 20172018 to 34.228.6 drilling rigs in the thirdsecond quarter of 2018.2019.


Drilling operating costs decreased $2.7$2.6 million or 8% between the comparative thirdsecond quarters of 20182019 and 2017.2018. The decrease was due primarily to less drilling rigs operating partially offset by increase in per day operating expense.operating. Contract drilling depreciation decreased $0.4$0.2 million or 3%2% in the thirdsecond quarter of 20182019 versus the thirdsecond quarter of 20172018 also due to less drilling rigs operating.operating and the transfer of 41 drilling rigs to assets held for sale partially offset by accelerated depreciation on drilling rigs stacked more than 49 months.


Mid-Stream


Our mid-stream revenues increased $6.4decreased $9.8 million or 12%18% in the thirdsecond quarter of 20182019 as compared to the thirdsecond quarter of 20172018 due primarily to higher volumeslower gas, NGLs, and increases in NGL and condensate prices partially offset by decreased natural gas prices. Gas processed volumes per day increased 14%3% between the comparative quarters primarily due to additional wells connected mainly to our processing systems.Cashion gathering system. Gas gathered volumes per day increased 8%19% between the comparative quarters due to connecting additional wells to our gathering and processing facilities primarily in Pennsylvania and Oklahoma.

Operating costs decreased $7.2 million or 18% in the second quarter of 2019 compared to the second quarter of 2018 primarily due to connecting new wells to our systems.

Operating costs increased $5.0 million or 13% in the third quarter of 2018 compared to the third quarter of 2017 primarily due to higherlower gas and purchase volumes and higher field direct and general and administrative expenses due to increased employee cost and from a $250,000 monthly service fee for outside services.prices. Depreciation and amortization increased $0.4$0.9 million, or 4%8%, primarily due to new capital assets placed in service.


Gain on Disposition of Assets


There was a $0.3$0.4 million gain on disposition of assets in the thirdsecond quarter of 2019 which was primarily related to assets held for sale that were sold which consisted of miscellaneous drilling rig components. For the second quarter of 2018, we had a gain of $0.2 million for the disposition of assets primarily due to the sale of drilling rig components and vehicles, compared to a gain of $0.1 million for the disposition of assets in the third quarter of 2017 primarily due to the sale of vehicles.


Other Income (Expense)


Interest expense, net of capitalized interest, decreased $1.6increased $0.9 million between the comparative thirdsecond quarters of 20182019 and 20172018 due primarily to a 21% decrease13% increase in average long-term debt outstanding in the thirdsecond quarter of 2018 and increased interest capitalized2019 partially offset by a higherlower average interest rate. We had interest earned of $0.4 million from the cash in our investment account from the excess proceeds from the sale of 50% of Superior. 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 thirdsecond quarter of 20182019 was $4.2 million compared to $4.0$4.3 million in the thirdsecond quarter of 2017,2018, and was netted against our gross interest of $12.5$13.2 million and $14.0$12.4 million for the thirdsecond quarters of 20182019 and 2017,2018, respectively. Our average interest rate increaseddecreased from 6.0%6.7% in the thirdsecond quarter of 20172018 to 6.7%6.5% in

the thirdsecond quarter of 20182019 and our average debt outstanding was $168.7$84.3 million lower in the third quarter of 2018 as compared to the third quarter of 2017 primarily due to the pay down of the Unit credit agreementhigher in the second quarter of 2018.2019 as compared to the second quarter of 2018 primarily due to additional capital expenditures over the last 12 months.


Loss
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Gain (Loss) on Derivatives


LossGain (loss) on derivatives increased $1.8by $22.4 million primarily due to losses on derivatives settled partially offset by a gain from fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.


Income Tax (Benefit) Expense


Income tax expense increased $5.0went from an expense of $2.0 million to a benefit of $1.9 million between the comparative thirdsecond quarters of 20182019 and 20172018 primarily due to increaseddecreased pre-tax income but was tempered to a certain degree by our lower statutory tax rate due to the 2017 Tax Act, and elimination of non-controlling interest income. Our effective tax rate was 24.2% for the third quarter of 2018 compared to 32.3%18.9% for the second quarter of 2017.2019 compared to 19.9% for the second quarter of 2018. The rate change was again primarily due to the lower federal statutorydecreased pre-tax income in relation to permanent tax rate due to the 2017 Tax Act and elimination of non-controlling interest income.differences. There was no current income tax expense or benefit in the thirdsecond quarter of 20182019 or 2017.2018. We paid $3.6 million inno income taxes in the thirdsecond quarter of 2018 related to our sale2019.

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Table of 50% of Superior. Under the guidance in ASC 810, Consolidation, we have determined that Superior is a VIE. The tax effects related to the gain recognized on the sale have been recorded to Capital in excess of par value.Contents


NineSix Months Ended SeptemberJune 30, 20182019 versus NineSix Months Ended SeptemberJune 30, 20172018
Provided below is a comparison of selected operating and financial data:
  Nine Months Ended September 30, 
Percent
Change
  2018 2017 
  (In thousands unless otherwise specified)  
Total revenue $628,493
 $534,793
 18 %
Net income $37,138
 $28,693
 29 %
Net income attributable to non-controlling interest $4,586
 $—
 — %
Net income attributable to Unit Corporation $32,552
 $28,693
 13 %
       
Oil and Natural Gas:      
Revenue $317,040
 $256,241
 24 %
Operating costs excluding depreciation, depletion, and amortization $100,519
 $95,873
 5 %
Depreciation, depletion, and amortization $97,797
 $71,544
 37 %
       
Average oil price received (Bbl) $56.40
 $47.62
 18 %
Average NGLs price received (Bbl) $23.03
 $17.05
 35 %
Average natural gas price received (Mcf) $2.35
 $2.50
 (6)%
Oil production (Bbl) 2,121,000
 1,990,000
 7 %
NGLs production (Bbl) 3,702,000
 3,476,000
 7 %
Natural gas production (Mcf) 41,572,000
 37,317,000
 11 %
Depreciation, depletion, and amortization rate (Boe) $7.32
 $5.76
 27 %
       
Contract Drilling:      
Revenue $143,527
 $128,059
 12 %
Operating costs excluding depreciation $95,593
 $91,213
 5 %
Depreciation $41,927
 $41,896
 — %
       
Percentage of revenue from daywork contracts 100% 100% — %
Average number of drilling rigs in use 32.7
 29.7
 10 %
Average dayrate on daywork contracts $17,327
 $16,120
 7 %
       
Mid-Stream:      
Revenue $167,926
 $150,493
 12 %
Operating costs excluding depreciation and amortization $124,441
 $111,862
 11 %
Depreciation and amortization $33,493
 $32,547
 3 %
       
Gas gathered—Mcf/day 393,414
 385,846
 2 %
Gas processed—Mcf/day 157,313
 133,986
 17 %
Gas liquids sold—gallons/day 651,979
 518,054
 26 %
       
Corporate and other:      
General and administrative expense $28,752
 $26,902
 7 %
Other depreciation $5,759
 $5,558
 4 %
Gain on disposition of assets $575
 $1,153
 (50)%
Other income (expense):      
Interest income $796
 $—
 — %
Interest expense, net $(26,474) $(28,807) (8)%
Gain (loss) on derivatives $(25,608) $21,019
 NM
Other $17
 $14
 21 %
Income tax expense $12,380
 $22,084
 (44)%
Average long-term debt outstanding $700,378
 $811,159
 (14)%
Average interest rate 6.5% 6.0% 8 %
_________________________
(1)NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

 Six Months Ended June 30,
Percent
Change (1)
 2019 2018 
(In thousands unless otherwise specified) 
Total revenue$354,837 $408,435 (13)%
Net income (loss)$(10,299)$16,015 (164)%
Net income attributable to non-controlling interest$1,714 $2,362 (27)%
Net income (loss) attributable to Unit Corporation$(12,013)$13,653 (188)%
Oil and Natural Gas:
Revenue$163,910 $205,417 (20)%
Operating costs excluding depreciation, depletion, and amortization$68,956 $68,380 1 %
Depreciation, depletion, and amortization$74,518 $62,337 20 %
Average oil price received (Bbl)$58.16 $55.76 4 %
Average NGLs price received (Bbl)$14.11 $21.65 (35)%
Average natural gas price received (Mcf)$2.18 $2.40 (9)%
Oil production (Bbl)1,414,000 1,429,000 (1)%
NGLs production (Bbl)2,417,000 2,425,000 — %
Natural gas production (Mcf)26,659,000 27,237,000 (2)%
Depreciation, depletion, and amortization rate (Boe)$8.64 $7.08 22 %
Contract Drilling:
Revenue$94,192 $92,915 1 %
Operating costs excluding depreciation$60,709 $63,561 (4)%
Depreciation$26,203 $27,038 (3)%
Percentage of revenue from daywork contracts100 %100 %— %
Average number of drilling rigs in use30.0 31.9 (6)%
Average dayrate on daywork contracts$18,412 $17,184 7 %
Mid-Stream:
Revenue$96,735 $110,103 (12)%
Operating costs excluding depreciation and amortization$71,846 $81,307 (12)%
Depreciation and amortization$23,828 $22,228 7 %
Gas gathered—Mcf/day457,859 382,005 20 %
Gas processed—Mcf/day163,725 155,799 5 %
Gas liquids sold—gallons/day681,070 627,305 9 %
Corporate and Other:
General and administrative expense$19,805 $19,474 2 %
Other depreciation$3,869 $3,836 1 %
Gain (loss) on disposition of assets$(1,193)$322 NM  
Other income (expense):
Interest income$44 $411 (89)%
Interest expense, net$(17,577)(18,144)(3)%
Gain (loss) on derivatives$995 $(21,223)NM  
Other$11 $11 — %
Income tax (benefit) expense$(2,318)$5,636 (141)%
Average long-term debt outstanding$710,494 $733,487 (3)%
Average interest rate6.5 %6.4 %2 %

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

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Oil and Natural Gas


Oil and natural gas revenues increased $60.8decreased $41.5 million or 24%20% in the first ninesix months 20182019 as compared to the first ninesix months of 20172018 primarily due to higher oil and NGLslower commodity prices and higher production volumes. In the first ninesix months of 2018,2019, as compared to the first ninesix months of 2017,2018, oil production increased 7%decreased 1%, natural gas production increased 11%decreased 2%, and NGLs production increased 7%.was essentially unchanged. Average oil prices increased 18%4% to $56.40$58.16 per barrel, average natural gas prices decreased 6%9% to $2.35$2.18 per Mcf, and NGLs prices increaseddecreased 35% to $23.03$14.11 per barrel.


Oil and natural gas operating costs increased $4.6$0.6 million or 5%1% between the comparative first ninesix months of 20182019 and 20172018 due to higher LOE, saltwater disposal, general and administrative expenses, and gross production tax partially offset by the impact of the change in classification of certain deducts due to the implementation on January 1, 2018 of ASC 606 Revenue Recognition reclass.lower LOE.


DD&A increased $26.3$12.2 million or 37%20% due primarily to a 27%22% increase in our DD&A rate and a 9% increasepartially offset by an 1% decrease in equivalent production. The increase in our DD&A rate in the first ninesix months of 20182019 compared to the first ninesix months of 20172018 resulted primarily from the cost of wells drilled in the last threesix months of 20172018 and the first ninesix months of 2018.2019.


Contract Drilling


Drilling revenues increased $15.5$1.3 million or 12%1% in the first ninesix months of 20182019 versus the first ninesix months of 2017.2018. The increase was due primarily to a 10%7% increase in the average dayrate partially offset by a 6% decrease in the average number of drilling rigs in use and an a 7% increaseuse. We also received $4.8 million in contract early termination fees during the average dayrate along with increased revenues from mobilizations.first six months of 2019. Average drilling rig utilization increaseddecreased from 29.731.9 drilling rigs in the first ninesix months of 20172018 to 32.730.0 drilling rigs in the first ninesix months of 2018.2019.


Drilling operating costs increased $4.4decreased $2.9 million or 5%4% between the comparative first ninesix months of 20182019 and 2017.2018. The increasedecrease was due primarily to moreless drilling rigs operating. Contract drilling depreciation decreased $0.8 million or 3% between the comparative first six months of 2019 and 2018. The decrease was essentially unchanged.also due to less drilling rigs operating and the transfer of 41 drilling rigs to assets held for sale partially offset by accelerated depreciation on drilling rigs stacked more than 49 months.


Mid-Stream


Our mid-stream revenues increased $17.4decreased $13.4 million or 12% in the first ninesix months of 20182019 as compared to the first ninesix months of 20172018 due due primarily to an increase inlower gas, NGLs, and condensate prices and volumes along with an increase in gas volumes sold partially offset by a decrease in natural gas prices. Gas processed volumes per day increased 17%5% between the comparative periods primarily due to connecting new wells at the Cashion and Hemphill processing facilities. Gas gathered volumes per day increased 2%20% between the comparative periods primarily due to connecting new wells at theour Cashion and Hemphill facilities partially offset by declines in volumes in the Appalachian area.Pittsburgh Mills facilities.


Operating costs increased $12.6decreased $9.5 million or 11%12% in the first ninesix months of 20182019 compared to the first ninesix months of 20172018 primarily due to increasedlower purchase volumes along with higher field direct and general and administrative expenses due to increased employee cost and from a $250,000 monthly outside service fee incurred in the second quarter.prices. Depreciation and amortization increased $0.9$1.6 million, or 3%7%, primarily due to new capital assets placed into service.

Other Depreciation

Other depreciation increased 4% during the first nine months of 2018 compared to the first nine months of 2017 due primarily to the ERP accounting and reporting system that was implemented during the first quarter of 2017.


General and Administrative


Corporate general and administrative expenses increased $1.9$0.3 million or 7%2% in the first ninesix months of 20182019 compared to the first ninesix months of 20172018 primarily due to higher employee costs and computer network costs.


Gain (Loss) on Disposition of Assets


There was an $0.6$1.2 million gainloss on disposition of assets in the first ninesix months of 2019. Of this amount, $0.2 million was related to assets held for sale that were sold which consisted of three drilling rigs and other drilling components. The other $1.0 million was related to the sales of other drilling rig components and vehicles. For the first six months of 2018, we had a gain of $0.3 million for the disposition of assets primarily due to the sale of drilling rig components and vehicles, compared to a gain of $1.2 million for the disposition of assets in the first nine months of 2017 primarily due to the sale of a corporate aircraft and vehicles.



Other Income (Expense)


Interest expense, net of capitalized interest, decreased $2.3$0.6 million between the comparative first ninesix months of 20182019 and 20172018 due primarily to a 14%3% decrease in the average long-term debt outstanding and an increase in interest capitalized partially offset by a higher average interest rate. We had interest earned of $0.8 million from the excess cash in our investment account from the sale of 50% of Superior. 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.
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Capitalized interest for the first ninesix months of 20182019 was $12.1$8.4 million compared to $11.9$7.9 million in the first ninesix months of 2017,2018, and was netted against our gross interest of $38.6$26.0 million and $40.7$26.1 million for the first ninesix months of 20182019 and 2017,2018, respectively. Our average interest rate increased from 6.0%6.4% to 6.5% and our average debt outstanding was $110.8$23.0 million lower in the first ninesix months of 20182019 as compared to the first ninesix months of 20172018 primarily due to the pay down of our Unit credit agreement in the second quarter of 2018.


Gain (Loss) on Derivatives


Gain (loss) on derivatives decreased $46.6increased $22.2 million primarily due to increased losses on derivaties settled along with losses on unrealized hedges comparedfluctuations in forward prices used to gains on unrealizedestimate the fair value in 2017.mark-to-market accounting.


Income Tax (Benefit) Expense


Income tax expense decreased $9.7went from an expense of $5.6 million to a benefit of $2.3 million between the comparative first ninesix months of 20182019 and 20172018 primarily due to decreased pre-tax income, lower statutory tax rate due to the 2017 Tax Act, and elimination of non-controlling interest income. Our effective tax rate was 25.0%18.4% for the first ninesix months of 20182019 compared to 43.5%26.0% for the first ninesix months of 2017.2018. The decrease was again primarily due to the lower federal statutorydecreased pre-tax income in relation to permanent tax rate due to the 2017 Tax Act, elimination of non-controlling interest income, and to a lesser extent, smaller deferred income tax expense related to our restricted stock vestings in the first nine months of 2018 as compared to the first nine months of 2017.differences. There was no current income tax expense or benefit in the first ninesix months of 20182019 or 2017.2018. We paid $3.6 million inno income taxes in the first ninesix months of 2018 related to the our sale of 50% of Superior. Under the guidance in ASC 810, Consolidation, we have determined that Superior is a VIE. The tax effects related to the gain recognized on the sale have been recorded to Capital in excess of par value.2019.


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;
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•our projected production guidelines for the year;
•our anticipated capital budgets;
•our financial condition and liquidity;liquidity (including our ability to refinance our senior subordinated notes);
•the number of wells our oil and natural gas segment plans to drill or rework during the year; and
our intended use of the proceeds from the sale of 50% of the interest we owned in our mid-stream segment; and
•our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods.


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


•the risk factors discussed in this report and in the documents we incorporate by reference;
•general economic, market, or business conditions;
•the availability of and nature of (or lack of) business opportunities that we pursue;
•demand for our land drilling services;
•changes in laws or regulations;
•changes in the current geopolitical situation;
•risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
•risks associated with future weather conditions;
•decreases or increases in commodity prices;
•putative class action lawsuits that may result in substantial expenditures and divert management's attention; and
•other factors, most of which are beyond our control.
You should not place undue reliance on these forward-looking statements. Except as required by law, we disclaim any intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after the date of this report to reflect the occurrence of unanticipated events.


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



Item 3. Quantitative and Qualitative Disclosure About Market Risk


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


Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas production. These prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our NGLs and natural gas production. Historically, these prices have fluctuated and we expect this to continue. The prices for oil, NGLs, and natural gas also affect the demand for our drilling rigs and the amount we can charge for the use of our drilling rigs. Based on our first ninesix months 20182019 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 $447,000$427,000 per month ($5.45.1 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 $225,000$224,000 per month ($2.7 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 $398,000$386,000 per month ($4.84.6 million annualized) change in our pre-tax operating cash flow.


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


At SeptemberJune 30, 2018,2019, these derivatives were outstanding:
TermCommodityContracted Volume
Weighted Average 

Fixed Price
Contracted Market
Oct'18Jul'19 – Oct'19Natural gas – swap30,00060,000 MMBtu/day$3.0052.900 IF – NYMEX (HH)
Nov’18Nov'19 – Dec'18Dec'19Natural gas – swap20,00040,000 MMBtu/day$3.0132.900 IF – NYMEX (HH)
Jan'19Jul'19 – Dec'19Natural gas – swap10,000 MMBtu/day$2.810IF – NYMEX (HH)
Oct'18Natural gas – basis swap10,00020,000 MMBtu/day$(0.190)(0.659)NGPL TEXOKPEPL
Oct'18Jul'19 – Dec'18Dec'19Natural gas – basis swap10,000 MMBtu/day$(0.678)(0.625)PEPLNGL MIDCON
Oct'18Jul'19 – Dec'18Dec'19Natural gas – basis swap10,00030,000 MMBtu/day$(0.568)(0.265)NGPL MIDCONTEXOK
Nov’18Jan'20 – Dec'18Dec'20Natural gas – basis swap10,00030,000 MMBtu/day$(0.208)(0.275)NGPL TEXOK
Jul'19 – Dec'19Natural gas – collar20,000 MMBtu/day$2.63 - $3.03IF – NYMEX (HH)
Jan'19Jul'19 – Dec'19Natural gas – basis swap20,000 MMBtu/day$(0.659)PEPL
Jan'19 – Dec'19Natural gas – basis swap10,000 MMBtu/day$(0.625)NGL MIDCON
Jan'19 – Dec'19Natural gas – basis swap30,000 MMBtu/day$(0.265)NGPL TEXOK
Jan'20 – Dec'20Natural gas – basis swap30,000 MMBtu/day$(0.275)NGPL TEXOK
Oct'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Oct'18 – Dec'18Crude oil – swap4,000 Bbl/day$53.52WTI – NYMEX
Oct'18 – Dec'18Crude oil – price differential risk500 Bbl/day$7.00LLS/WTI
Oct'18 – Dec'18Crude oil – three-way collar2,000 Bbl/day$47.50 - $37.50 - $56.08WTI – NYMEX
Jan'19 – Dec'19Crude oil – three-way collar4,000 Bbl/day$61.25 - $51.25 - $72.93WTI – NYMEX


After September 30, 2018, the following derivatives were entered into:
TermCommodityContracted Volume
Weighted Average 
Fixed Price
Contracted Market
Jan'19 – Dec'19Natural gas – swap10,000 MMBtu/day$2.850IF – NYMEX (HH)
Jan'19 – Dec'19Natural gas – collar20,000 MMBtu/day$2.63 - $3.03IF – NYMEX (HH)
Jan'19 – Mar'19Natural gas – three-way collar10,000 MMBtu/day$3.00 - $2.75 - $4.35IF – NYMEX (HH)

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreements and the Notes. The credit agreement, at our election bears interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election, borrowings under our credit agreements may be fixed at the LIBOR Rate for periods of up to 180 days. AsBased on our average outstanding long-term debt subject to a variable rate in the first six months of October 19, 2018,

we did not have any outstanding debt under2019, a 1% increase in the floating rate would reduce our credit agreements.annual pre-tax cash flow by approximately $0.6 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).


Item 4. Controls and Procedures


Our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) (Disclosure Controls) or our internal control over financial reporting (ICFR) 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 control.controls. The design of any system of controls also is based in part on certain assumptions about the likelihood of future events, and there is no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to an error or fraud may occur and not be detected. We monitor our Disclosure Controls and ICFR and make modifications as necessary; our intent in this regard is that the Disclosure Controls and ICFR will be modified as systems change, and conditions warrant.


Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our Disclosure Controlsdisclosure controls and procedures under the Exchange Act in ensuring the information required to be disclosed in the reports that we file or submit under the Exchange Act 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 CEO, CFO, and management as appropriate to allow timely decisions regarding required disclosure.

Rule 13a-15. Based on that evaluation, our CEO and CFO concluded that our Disclosure Controls were notdisclosure controls and procedures are effective as of SeptemberJune 30, 2018 due to a material weakness in ICFR described below.

Material Weakness in Internal Control Over Financial Reporting. A material weakness is a deficiency, or combination of deficiencies, in ICFR, such that there is2019 at a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis.assurance level.


We did not design and maintain effective controls to verify the proper presentation and disclosure of our interim and annual consolidated financial statements. Specifically, our controls were not sufficiently precise to allow for the effective review of the underlying information used in the preparation of the consolidated financial statements, nor verify that transactions were appropriately presented.This control deficiency led to a misstatement that resulted in the revision of our statement of cash flows for the year ended December 31, 2017, and the restatement of our statement of cash flows for the interim period ended March 31, 2018. This material weakness could result in misstatements of the annual or interim consolidated financial statements or disclosures that would not be prevented or detected.

Plan for Remediation of the Material Weakness. We have dedicated significant time and resources that we believe will address the underlying cause of the material weakness, including:

engaged a consultant specializing in internal controls to assist with the remediation efforts;
recruited, added, and trained an additional staff position in the financial reporting department;
redesigned and enhanced controls related to the preparation and review of the consolidated financial statements; and
provided additional training to financial reporting personnel with respect to the preparation and review of the consolidated financial statements.

Management believes the measures described above will remediate the material weakness that we have identified. This material weakness will not be considered remediated until the applicable remedial controls operate for a sufficient period of time. As management continues to evaluate and improve internal controls over financial reporting, we may decide to take additional measures to address this control deficiency or determine to modify certain of the remediation measures.


Changes in Internal Controls. There were no other changes in our internal control over financial reporting (ICFR)ICFR during the quarter ended SeptemberJune 30, 2018,2019, that materially affected our ICFR or are reasonably likely to materially affect it, as defined in Rule 13a – 15(f) under the Exchange Act.



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PART II. OTHER INFORMATION

Item 1. Legal Proceedings


Panola Independent School District No. 4, et al. v. Unit Petroleum Company, No. CJ-07-215, District Court of Latimer County, Oklahoma.

Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita Golightly, Melody Culberson, and Charlotte Abernathy are the Plaintiffs 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 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 in Latimer, Le Flore, and Pittsburg Counties, Oklahoma. In July 2014, a second class certification hearing was held where, besides 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. ThereOn July 29, 2019, the trial court entered its order denying the Plaintiffs’ amended motion for class certification. Once the trial court’s order is no timetable for whenappealable, the courtPlaintiffs’ will issue its ruling. The merits of Plaintiffs’ claims will remain stayed while class certification issues are pending.have 30 days to appeal the decision.


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.


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


On November 3, 2016, a putative class action lawsuit was filed against Unit Petroleum Company styled Chieftain Royalty Company v. Unit Petroleum Company in LeFlore County, Oklahoma. Plaintiff alleges that Unit Petroleum breached its duty to pay royalties on natural gas used for fuel off the lease premises. The lawsuit seeks actual and punitive damages, an accounting, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of Oklahoma citizens who are or were royalty owners in our Oklahoma wells. We filed a motion to dismiss on the basis that the claims asserted by the Plaintiff and the putative class are barred because they have already been asserted by the putative class in the Panola lawsuit and are subject to its reversal of class certification. The court denied our motion to dismiss and we have asked the court to certify its order so that it can be immediately appealed. That issue is still pending before the court. If we do not ultimately prevail on our claim of issue preclusion, we have several other 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 wrongfully withheld. At this point, the issue of class certification has not been set before the court.


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.



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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, 2017,2018, 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.


ThereExcept as set forth below, there have been no material changes to the risk factors disclosed in Item 1A in our Form 10-K for the year ended December 31, 2017.2018.


Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect our indebtedness.

Our variable rate debt under both the Unit credit agreement and the Superior credit agreement is tied to LIBOR. On July 27, 2017, the Financial Conduct Authority announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. There is no guarantee that a transition from LIBOR to an alternative will not result in financial market disruptions, significant increases in benchmark rates or borrowing costs to borrowers, any of which could have an adverse effect on our business, financial condition and results of operations.

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


The following table provides information relating to our repurchase of common stock for the three months ended SeptemberJune 30, 2018:2019:
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, 2018 to July 31, 2018—
$—
—
—
August 1, 2018 to August 31, 2018—
—
—
—
September 1, 2018 to September 30, 2018—
—
—
—
Total—
$—
—
—
Period
(a)
Total Number of Shares Purchased (1)
(b)
Average Price Paid
Per Share (2)
(c)
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs		(d)
Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
April 1, 2019 to April 30, 2019— $— — — 
May 1, 2019 to May 31, 2019577 11.76 577 — 
June 1, 2019 to June 30, 2019— — — — 
Total577 $11.76 577 — 

 _______________________
1.The shares were repurchased to remit withholding of taxes on the value of stock distributed with the second quarter 2019 vesting of restricted stock for grants previously made from our "Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015."

2.The price paid per common share represents the closing sales price of a share of our common stock as reported by the NYSE on the day that the stock was acquired by us.

Item 3. Defaults Upon Senior Securities


Not applicable.


Item 4. Mine Safety Disclosures


Not applicable.


Item 5. Other Information


Not applicable.



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Item 6. Exhibits


Exhibits:
 
10.131.1 
31.1
Certification of Chief Executive Officer under Rule 13a – 14(a) of the Exchange Act.
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.
_______________________
*Certain schedules referenced in the agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule will be furnished supplementary to the U.S. Securities and Exchange Commission upon request.

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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:NovemberAugust 6, 20182019
By: /s/ Larry D. Pinkston
LARRY D. PINKSTON
Chief Executive Officer and Director
Date:NovemberAugust 6, 20182019
By: /s/ Les Austin
LES AUSTIN
Senior Vice President and Chief Financial Officer



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