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 June 30, 20162017
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]
image2a01a08.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, Oklahoma74132
(Address of principal executive offices)(Zip Code)
(918) 493-7700
(Registrant’s telephone number, including area code)
None
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [x]            No [  ]                                                     
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [x]            No [  ]                                                     
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” andfiler,” “smaller reporting company”company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [x]    Accelerated filer [ x ]    Non-accelerated filer (Do not check if a smaller reporting company) [  ]
Smaller reporting company [  ]    Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    [ ]  

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [  ]            No [x]  
As of July 22, 2016, 51,503,67221, 2017, 52,886,592 shares of the issuer's common stock were outstanding.


Table of Contents

TABLE OF CONTENTS
 
  
Page
Number
  
   
Item 1. 
   
 
   
 
   
 
   
 
   
Item 2.
   
Item 3.
   
Item 4.
   
  
   
Item 1.
   
Item 1A.
   
Item 2.
   
Item 3.
   
Item 4.
   
Item 5.
   
Item 6.
   
 

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, in the future, 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 in the future 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 our legal proceedings involving us will not materially affect our financial results;
our ability to timely secure third-party services used in completing our wells;
our ability to transport or convey our oil 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;
the number of wells our oil and natural gas segment plans to drill or rework during the year; and
our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may be requiredhave to record in future periods.
These statements are based on assumptions and analyses made by us in light ofbased 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;
our ability to successfully implement our pending technology conversion process relating to our financialputative class action lawsuits that may result in substantial expenditures and operational information systems;divert management's attention; and
other factors, most of which are beyond our control.
You should not place undue reliance on any of these forward-looking statements. Except as required by law, we disclaim any current intention to update forward-looking information and to release publicly the results of any future revisions we may

make to forward-looking statements to reflect events or circumstances after the date of this document to reflect unanticipated events.


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 June 30,
2016
 December 31,
2015
 June 30,
2017
 December 31,
2016
 (In thousands except share amounts) (In thousands except share amounts)
ASSETS        
Current assets:        
Cash and cash equivalents $974
 $835
 $849
 $893
Accounts receivable, net of allowance for doubtful accounts of $5,174 and $5,199 at June 30, 2016 and December 31, 2015, respectively 67,506
 79,941
Accounts receivable, net of allowance for doubtful accounts of $2,888 and $3,773 at June 30, 2017 and December 31, 2016, respectively 94,998
 83,954
Materials and supplies 3,324
 3,565
 3,291
 3,340
Current derivative asset (Note 10) 
 10,186
 3,948
 
Current income tax receivable 2,033
 21,002
 114
 99
Current deferred tax asset 8,598
 14,206
Assets held for sale 
 615
Current deferred tax asset (Note 8) 
 25,211
Prepaid expenses and other 6,859
 9,908
 6,304
 7,699
Total current assets 89,294
 140,258
 109,504
 121,196
Property and equipment:        
Oil and natural gas properties on the full cost method:        
Proved properties 5,420,972
 5,401,618
 5,540,086
 5,446,305
Unproved properties not being amortized 321,191
 337,099
 337,190
 314,867
Drilling equipment 1,567,765
 1,567,560
 1,587,096
 1,565,268
Gas gathering and processing equipment 697,573
 689,063
 711,355
 705,859
Saltwater disposal systems 60,527
 60,316
 62,191
 60,638
Corporate land and building 56,149
 49,890
 59,075
 59,066
Transportation equipment 34,055
 40,072
 29,704
 32,842
Other 45,777
 45,489
 52,799
 48,590
 8,204,009
 8,191,107
 8,379,496
 8,233,435
Less accumulated depreciation, depletion, amortization, and impairment 5,818,163
 5,609,980
 6,044,966
 5,952,330
Net property and equipment 2,385,846
 2,581,127
 2,334,530
 2,281,105
Goodwill 62,808
 62,808
 62,808
 62,808
Non-current derivative asset (Note 10) 
 968
 689
 377
Other assets 14,148
 14,681
 15,779
 13,817
Total assets $2,552,096
 $2,799,842
 $2,523,310
 $2,479,303

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

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

 June 30,
2016
 December 31,
2015
 June 30,
2017
 December 31,
2016
 (In thousands except share amounts) (In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY        
Current liabilities:        
Accounts payable $72,744
 $87,413
 $106,200
 $88,793
Accrued liabilities (Note 5) 46,368
 46,918
 39,092
 39,651
Current derivative liability (Note 10) 9,646
 
 1,036
 21,564
Current portion of other long-term liabilities (Note 6) 17,999
 16,560
 14,593
 14,907
Total current liabilities 146,757
 150,891
 160,921
 164,915
Long-term debt less debt issuance costs (Note 6) 875,051
 918,995
 806,092
 800,917
Non-current derivative liability (Note 10) 3,420
 285
 
 415
Other long-term liabilities (Note 6) 103,926
 140,341
 100,796
 103,064
Deferred income taxes 211,721
 275,750
Deferred income taxes (Note 8) 211,038
 215,922
Commitments and contingencies (Note 12) 
 
Shareholders’ equity:        
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued 
 
 
 
Common stock, $.20 par value, 175,000,000 shares authorized, 51,504,959 and 50,413,101 shares issued as of June 30, 2016 and December 31, 2015, respectively 10,016
 9,831
Common stock, $.20 par value, 175,000,000 shares authorized, 52,889,118 and 51,494,318 shares issued as of June 30, 2017 and December 31, 2016, respectively 10,277
 10,016
Capital in excess of par value 497,312
 486,571
 527,624
 502,500
Accumulated other comprehensive income (Note 13) 20
 
Retained earnings 703,893
 817,178
 706,542
 681,554
Total shareholders’ equity 1,211,221
 1,313,580
 1,244,463
 1,194,070
Total liabilities and shareholders’ equity $2,552,096
 $2,799,842
 $2,523,310
 $2,479,303

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


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
 Three Months Ended Six Months Ended Three Months Ended Six Months Ended
 June 30, June 30, June 30, June 30,
 2016 2015 2016 2015 2017 2016 2017 2016
 (In thousands except per share amounts) (In thousands except per share amounts)
Revenues:                
Oil and natural gas $69,190
 $107,256
 $127,464
 $213,325
 $83,173
 $69,190
 $170,771
 $127,464
Contract drilling 24,257
 55,015
 62,967
 150,092
 39,255
 24,257
 76,440
 62,967
Gas gathering and processing 44,858
 52,176
 84,058
 106,129
 48,153
 44,858
 99,094
 84,058
Total revenues 138,305
 214,447
 274,489
 469,546
 170,581
 138,305
 346,305
 274,489
Expenses:                
Oil and natural gas:        
Operating costs 33,331
 45,972
 66,677
 91,183
Operating costs:        
Oil and natural gas 32,758
 33,331
 61,962
 66,677
Contract drilling 27,239
 19,254
 56,466
 47,352
Gas gathering and processing 36,042
 32,381
 73,746
 63,447
Total operating costs 96,039
 84,966
 192,174
 177,476
Depreciation, depletion, and amortization 30,411
 68,101
 62,243
 145,219
 50,080
 52,878
 97,012
 108,468
Impairment of oil and natural gas properties (Note 2) 74,291
 410,536
 112,120
 811,129
Contract drilling:        
Operating costs 19,254
 36,485
 47,352
 88,231
Depreciation 10,918
 13,265
 23,113
 28,278
Impairment of contract drilling equipment (Note 3) 
 8,314
 
 8,314
Gas gathering and processing:        
Operating costs 32,381
 40,592
 63,447
 84,767
Depreciation and amortization 11,515
 10,848
 22,974
 21,542
Impairments (Note 2) 
 74,291
 
 112,120
General and administrative 8,382
 9,624
 17,097
 18,994
 8,713
 8,348
 17,667
 16,959
Gain on disposition of assets (477) (415) (669) (960) (248) (477) (1,072) (669)
Total operating expenses 220,006
 643,322
 414,354
 1,296,697
 154,584
 220,006
 305,781
 414,354
Loss from operations (81,701) (428,875) (139,865) (827,151)
Income (loss) from operations 15,997
 (81,701) 40,524
 (139,865)
Other income (expense):                
Interest, net (10,606) (7,956) (20,223) (15,196) (9,467) (10,606) (18,863) (20,223)
Gain (loss) on derivatives (22,672) (1,919) (11,743) 4,667
 8,902
 (22,672) 23,633
 (11,743)
Other 1
 24
 (14) 22
Other, net 6
 1
 9
 (14)
Total other income (expense) (33,277) (9,851) (31,980) (10,507) (559) (33,277) 4,779
 (31,980)
Loss before income taxes (114,978) (438,726) (171,845) (837,658)
Income (loss) before income taxes 15,438
 (114,978) 45,303
 (171,845)
Income tax expense (benefit):                
Current 
 803
 
 868
Deferred (42,842) (165,140) (58,560) (315,783) 6,379
 (42,842) 20,315
 (58,560)
Total income taxes (42,842) (164,337) (58,560) (314,915) 6,379
 (42,842) 20,315
 (58,560)
Net loss $(72,136) $(274,389) $(113,285) $(522,743)
Net loss per common share:        
Net income (loss) $9,059
 $(72,136) $24,988
 $(113,285)
Net income (loss) per common share:        
Basic $(1.44) $(5.58) $(2.27) $(10.66) $0.18
 $(1.44) $0.49
 $(2.27)
Diluted $(1.44) $(5.58) $(2.27) $(10.66) $0.17
 $(1.44) $0.49
 $(2.27)

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


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
 Three Months Ended Six Months Ended
 June 30, June 30,
 2017 2016 2017 2016
 (In thousands)
Net income (loss)$9,059
 $(72,136) $24,988
 $(113,285)
Other comprehensive income, net of taxes:       
Unrealized appreciation on securities, net of tax of $12, $0, $12, and $020
 
 20
 
Comprehensive income (loss)$9,079
 $(72,136) $25,008
 $(113,285)

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


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 Six Months Ended Six Months Ended
 June 30, June 30,
 2016 2015 2017 2016
 (In thousands) (In thousands)
OPERATING ACTIVITIES:        
Net loss $(113,285) $(522,743)
Adjustments to reconcile net loss to net cash provided by operating activities:    
Net income (loss) $24,988
 $(113,285)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation, depletion, and amortization 109,522
 196,576
 97,012
 108,468
Impairments (Notes 2 and 3) 112,120
 819,443
Impairments (Note 2) 
 112,120
Amortization of debt issuance costs and debt discount 1,075
 1,054
(Gain) loss on derivatives 11,743
 (4,667) (23,633) 11,743
Cash receipts on derivatives settled 12,192
 21,082
Deferred tax benefit (58,560) (315,783)
Cash (payments) receipts on derivatives settled (1,569) 12,192
Deferred tax expense (benefit) 20,315
 (58,560)
Gain on disposition of assets (946) (960) (1,072) (946)
Employee stock compensation plans 7,703
 12,329
 8,066
 7,703
Other, net (2,755) 1,944
 299
 (2,755)
Changes in operating assets and liabilities increasing (decreasing) cash:        
Accounts receivable 5,443
 77,894
 (15,087) 5,443
Accounts payable 24,077
 (16,327) 3,724
 24,077
Material and supplies 241
 (2,366) 49
 241
Accrued liabilities 3,411
 (11,811) 756
 3,411
Income taxes 18,969
 (1,845) (15) 18,969
Other, net 2,841
 4,840
 2,147
 2,841
Net cash provided by operating activities 132,716
 257,606
 117,055
 132,716
INVESTING ACTIVITIES:        
Capital expenditures (124,182) (371,572) (107,933) (124,182)
Producing properties and other acquisitions (Note 3) (52,956) 
Proceeds from disposition of assets 46,627
 5,130
 19,556
 46,627
Other 169
 
 (1,500) 169
Net cash used in investing activities (77,386) (366,442) (142,833) (77,386)
FINANCING ACTIVITIES:        
Borrowings under credit agreement 150,300
 396,000
 160,600
 150,300
Payments under credit agreement (195,300) (281,500) (156,500) (195,300)
Payments on capitalized leases (1,828) (1,757) (1,901) (1,828)
Tax (benefit) expense from stock compensation (376) 4
Proceeds from common stock issued, net of issue costs (Note 13) 18,623
 
Tax benefit from stock compensation 
 (376)
Book overdrafts (7,987) (4,121) 4,912
 (7,987)
Net cash (used in) provided by financing activities (55,191) 108,626
Net cash provided by (used in) financing activities 25,734
 (55,191)
Net increase (decrease) in cash and cash equivalents 139
 (210) (44) 139
Cash and cash equivalents, beginning of period 835
 1,049
 893
 835
Cash and cash equivalents, end of period $974
 $839
 $849
 $974

Supplemental disclosure of cash flow information:        
Cash paid during the year for:        
Interest paid (net of capitalized) 19,830
 15,886
 16,813
 19,830
Income taxes 
 3,142
 
 
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment 30,758
 92,743
 (8,771) 30,758
Non-cash reductions to oil and natural gas properties related to asset retirement obligations 28,884
 5,956
 1,579
 28,884
The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PREPARATION AND PRESENTATION

The accompanying 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.

The accompanying 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 25, 2016,28, 2017, for the year ended December 31, 20152016.

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

Balance Sheets at June 30, 20162017 and December 31, 2015;2016;
Statements of Operations for the three and six months ended June 30, 20162017 and 2015;2016;
Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2017 and 2016; and
Statements of Cash Flows for the six months ended June 30, 20162017 and 20152016.

Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and accompanying notes. Actual results may differ from those estimates. Results for the six months ended June 30, 20162017 and 20152016 are not necessarily indicative of the results to be realized for the full year of 20162017, or that we realized for the full year of 20152016.

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

NOTE 2 – OIL AND NATURAL GAS PROPERTIES
    
Full cost accounting rules require us to review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is referred to as the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the unescalated 12-month average price of our oil, NGLs, and natural gas), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. If the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short while. Once incurred, a write-down of oil and natural gas properties is not reversible.

During the first quarter of 2015, the 12-month average commodity prices decreased significantly, resulting in a non-cash ceiling test write-down of $400.6 million pre-tax ($249.4 million, net of tax). During theand second quarter of 2015, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of $410.5 million pre-tax ($255.6 million, net of tax).

During the first quarter of 2016, the 12-month average commodity prices continued to decrease, resulting inwe had a non-cash ceiling test write-down of $37.8 million pre-tax ($23.5 million, net of tax). For the second quarter of 2016, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of and $74.3 million pre-tax ($46.3 million, net of tax)., respectively. We had no non-cash ceiling test write-downs for the first or second quarter of 2017.


NOTE 3 – ACQUISITIONS AND DIVESTITURES

OilAcquisitions

On April 3, 2017, we closed on an acquisition of certain oil and Natural Gasnatural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The preliminary adjusted value of consideration given was $54.0 million.

As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition adds approximately 8,300 net oil and gas

leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. Of the acreage acquired, approximately 71% is held by production. We also received one gathering system as part of the transaction.

We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations, which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed. It is based on information available to us at the time these unaudited condensed consolidated financial statements were prepared. We believe these estimates are reasonable; however, the estimates are subject to change as additional information becomes available and is assessed by us (in thousands):
Preliminary Purchase Price 
Total consideration given$54,000
  
Preliminary Allocation of Purchase Price 
Oil and natural gas properties included in the full cost pool: 
Proved oil and natural gas properties$43,413
Undeveloped oil and natural gas properties8,650
Total oil and natural gas properties included in the full cost pool (1)
52,063
Gas gathering equipment and other2,340
Asset retirement obligation(403)
Fair value of net assets acquired$54,000
(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.
The pro forma effects of this acquired business is immaterial to the results of operations.

Divestitures

We sold non-core oil and natural gas assets, net of related expenses, for $17.8 million during the first six months of 2017, compared to $43.6 million during the first six months of 2016, compared to less than $0.1 million during the first six months of 2015.2016. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

Contract Drilling

During the second quarter of 2015, we recorded a write-down of approximately $8.3 million pre-tax on drilling equipment that was being held for sale.

NOTE 4 – LOSSEARNINGS (LOSS) PER SHARE

Information related to the calculation of lossearnings (loss) per share follows:
 
Loss
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
Earnings (Loss)
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 (In thousands except per share amounts) (In thousands except per share amounts)
For the three months ended June 30, 2017      
Basic earnings per common share $9,059
 51,366
 $0.18
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) 
 578
 (0.01)
Diluted earnings per common share $9,059
 51,944
 $0.17
For the three months ended June 30, 2016            
Basic loss per common share $(72,136) 50,074
 $(1.44)
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) 
 
 
Diluted loss per common share $(72,136) 50,074
 $(1.44)
For the three months ended June 30, 2015      
Basic loss per common share $(274,389) 49,148
 $(5.58) $(72,136) 50,074
 $(1.44)
Effect of dilutive stock options, restricted stock, and SARs 
 
 
 
 
 
Diluted loss per common share $(274,389) 49,148
 $(5.58) $(72,136) 50,074
 $(1.44)

Due to the net loss for the three months ended June 30, 2016, approximately 417,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the above earnings per share calculation. For the three months ended June 30, 2015, approximately 307,000 weighted average shares were excluded.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 Three Months Ended
 June 30, June 30,
 2016 2015 2017 2016
Stock options and SARs 240,270
 259,085
 178,755
 240,270
Average exercise price $49.29
 $50.50
 $47.75
 $49.29

 
Loss
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 Earnings (Loss)
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 (In thousands except per share amounts) (In thousands except per share amounts)
For the six months ended June 30, 2017      
Basic income per common share $24,988
 50,832
 $0.49
Effect of dilutive stock options, restricted stock, and SARs 
 539
 
Diluted income per common share $24,988
 51,371
 $0.49
For the six months ended June 30, 2016            
Basic loss per common share $(113,285) 49,977
 $(2.27) $(113,285) 49,977
 $(2.27)
Effect of dilutive stock options, restricted stock, and SARs 
 
 
 
 
 
Diluted loss per common share $(113,285) 49,977
 $(2.27) $(113,285) 49,977
 $(2.27)
For the six months ended June 30, 2015      
Basic loss per common share $(522,743) 49,063
 $(10.66)
Effect of dilutive stock options, restricted stock, and SARs 
 
 
Diluted loss per common share $(522,743) 49,063
 $(10.66)

Because of the net loss for the six months ended June 30, 2016, approximately 332,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the above earnings per share calculation. For the six months ended June 30, 2015, approximately 206,000 weighted average shares were excluded.calculation above.

The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
 Six Months Ended Six Months Ended
 June 30, June 30,
 2016 2015 2017 2016
Stock options and SARs 240,270
 261,270
 178,755
 240,270
Average exercise price $49.29
 $50.34
 $47.75
 $49.29


NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:of:
 June 30,
2016
 December 31,
2015
 June 30,
2017
 December 31,
2016
 (In thousands) (In thousands)
Employee costs $10,526
 $15,394
Lease operating expenses $19,157
 $17,220
 10,047
 10,075
Interest payable 6,684
 6,524
Taxes 8,722
 3,767
 6,577
 2,219
Employee costs 7,007
 12,641
Interest payable 6,213
 6,321
Third-party credits 2,954
 3,326
 2,149
 2,998
Derivative settlements 278
 
Other 2,037
 3,643
 3,109
 2,441
Total accrued liabilities $46,368
 $46,918
 $39,092
 $39,651
 

NOTE 6 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

Our long-term debt consisted of the following as of the dates indicated:indicated consisted of the following:
 June 30,
2016
 December 31,
2015
 June 30,
2017
 December 31,
2016
 (In thousands) (In thousands)
Credit agreement with an average interest rate of 3.9% and 2.6% at June 30, 2016 and December 31, 2015, respectively $236,000
 $281,000
Credit agreement with an average interest rate of 3.5% and 2.8% at June 30, 2017 and December 31, 2016, respectively $164,900
 $160,800
6.625% senior subordinated notes due 2021 650,000
 650,000
 650,000
 650,000
Total principal amount 886,000
 931,000
 814,900
 810,800
Less: unamortized discount (3,076) (3,338) (2,524) (2,804)
Less: debt issuance costs, net (7,873) (8,667) (6,284) (7,079)
Total long-term debt $875,051
 $918,995
 $806,092
 $800,917

Credit Agreement. On April 8, 2016, we amended ourOur Senior Credit Agreement (credit agreement) is scheduled to mature on April 10, 2020. TheUnder the credit agreement, the amount we can borrow is the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed the maximum credit agreement amount of $875.0 million. Our elected commitment amount is $475.0 million. Our borrowing base is $475.0 million. We are charged a commitment fee of 0.50% on the amount available but not borrowed. TheThat fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. WithUnder the new amendment,credit agreement, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our midstream affiliate, Superior Pipeline Company, L.L.C.

The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the credit agreement.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At June 30, 2016,2017, we had $236.0$164.9 million of outstanding borrowings under our credit agreement.

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

The credit agreement prohibits, among other things:

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


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

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

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

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

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

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

As of June 30, 20162017, we were in compliance with the covenants in the credit agreement.agreement covenants.

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 will 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 the issuance ofissuing the Notes. The Guarantors are most of our direct and indirect subsidiaries. The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.

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

On and after May 15, 2016, weWe may redeem all or, from time to time,occasionally, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that among other things, 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 June 30, 20162017.



Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
 June 30,
2016
 December 31,
2015
 June 30,
2017
 December 31,
2016
 (In thousands) (In thousands)
Asset retirement obligation (ARO) liability $70,926
 $98,297
 $70,049
 $70,170
Capital lease obligations 20,710
 22,466
 17,089
 18,918
Workers’ compensation 15,258
 16,551
 13,971
 15,163
Separation benefit plans 6,386
 9,886
 5,456
 4,943
Deferred compensation plan 4,430
 4,244
 5,092
 4,578
Gas balancing liability 3,805
 5,047
 3,322
 3,789
Other 410
 410
 410
 410
 121,925
 156,901
 115,389
 117,971
Less current portion 17,999
 16,560
 14,593
 14,907
Total other long-term liabilities $103,926
 $140,341
 $100,796
 $103,064

Estimated annual principal payments under the terms of debt and other long-term liabilities during each of the five successive twelve month periods beginning July 1, 20162017 (and through 2021) are $18.0$14.6 million, $44.3$45.6 million, $10.2$173.6 million, $244.1$659.6 million, and $658.7$2.5 million, respectively.

Capital Leases

DuringIn 2014, our mid-stream segment entered into capital lease agreements for twenty20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $3.8 million current portion of our capital lease obligations of $3.6 million is included in current portion of other long-term liabilities and the non-current portion of $17.1$13.3 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of June 30, 20162017. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $8.6$6.8 million and $2.3$1.5 million, respectively, at June 30, 20162017. Annual payments, net of maintenance and interest, average $4.0$4.1 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value at that time.value.

Future payments required under the capital leases at June 30, 2016:2017:
 Amount Amount
Ending June 30, (In thousands)
Beginning July 1, (In thousands)
2017 $6,168
 $6,168
2018 6,168
 6,168
2019 6,168
 6,168
2020 6,168
 6,673
2021 and thereafter 6,853
2021 179
Total future payments 31,525
 25,356
Less payments related to:    
Maintenance 8,552
 6,767
Interest 2,263
 1,500
Present value of future minimum payments $20,710
 $17,089


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 of our AROs relate to the plugging costs associated with our oil and gas wells.

The following table shows certain information about our AROs for the periods indicated:
 Six Months Ended Six Months Ended
 June 30, June 30,
 2016 2015 2017 2016
 (In thousands) (In thousands)
ARO liability, January 1: $98,297
 $100,567
 $70,170
 $98,297
Accretion of discount 1,513
 1,757
 1,458
 1,513
Liability incurred 212
 5,986
 1,018
 212
Liability settled (605) (1,566) (1,224) (605)
Liability sold (1)
 (10,308) (246) (1,412) (10,308)
Revision of estimates (2)
 (18,183)
(10,130) 39

(18,183)
ARO liability, June 30: 70,926
 96,368
 70,049
 70,926
Less current portion 3,523
 3,277
 2,825
 3,523
Total long-term ARO $67,403
 $93,091
 $67,224
 $67,403
_______________________ 
(1)We sold approximately 1,150our interest in a number of non-core wells to unaffiliated third-parties during the first six months of 2016.2017 and 2016, respectively.
(2)Plugging liability estimates were revised in both 20162017 and 20152016 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS

Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting.Compensation. The FASB has issued ASU 2016-09.2017-09, to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms and conditions of a share-based payment award. The amendments are effective for reporting periods beginning after December 15, 2017. We are in the process of evaluating the impact these amendments will have on our financial statements.

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

Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to improve the accountinghelp companies and other organizations evaluate whether transactions should be accounted for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspectsas acquisitions (or disposals) of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equityassets or liabilities; and (c) classification on the statement of cash flows.businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2016,2017. We are in the process of evaluating the impact these amendments will have on our financial statements.

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

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

December 15, 2018, and interim periods within those annual periods. Early adoption of the amendments is permitted. We are in the process of evaluating the impact itthese amendments will have on our financial statements.

Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. The amendments will require current deferred tax assets to be combined with noncurrent deferred tax assets. We do not believe the amendments will have a material impact on our financial statements.

Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The FASB has issued ASU 2015-03. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the

balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The FASB has also issued ASU 2015-15. The amendments in this ASU allow an entity to defer and present debt issuance cost as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We have maintained debt issuance costs associated with our credit agreement as an asset and amortize these fees over the life of the credit agreement. For public business entities, the amendments are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. We have adopted these amendments during the first quarter of 2016. Previously, debt issuance costs associated with the Notes was classified as a long-term asset on the balance sheet, but with ASU 2015-03, it is presented as a direct deduction from the carrying amount of the recognized debt liability.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This affectsThese amendments affect any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the guidanceamendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-12, "Narrow-Scope Improvements and Practical Expedients," which provides clarifying guidance in certain areas and adds some practical expedients. Also in May 2016, the FASB issued ASU 2016-11, "Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting." This ASUamendment rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities—Activities- Oil and Gas, effective uponon the adoption of Topic 606, Revenue from Contracts with Customers. In April 2016, the FASB issued ASU 2016-10, "Identifying Performance Obligations and Licensing," which amends the revenue guidance on identifying performance obligations and accounting for licenses of intellectual property. The FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We will adopt these amendments effective January 1, 2018. We are utilizing a bottom-up approach to analyze the impact of the new standard on our contracts by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard. We have an implementation team evaluating contracts for the various revenue streams of our business segments to address changes to business processes, systems, and controls. While we have not identified any material differences in the processamount and timing of evaluatingrevenue recognition to date, our evaluation is not complete, and we have not reached a conclusion on the overall impacts of adopting Topic 606. Topic 606 provides for adoption either retrospectively to each prior reporting period presented or as a cumulative effect adjustment to retained earnings at the date of adoption. We plan to adopt using the cumulative effect method.

Adopted Standards

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

Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments primarily impact it willclassification within the statement of cash flows between financial and operating activities. This did not have a material impact on our financial statements.


NOTE 9 – STOCK-BASED–STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:
 Three Months Ended Six Months Ended Three Months Ended Six Months Ended
 June 30, June 30, June 30, June 30,
 2016 2015 2016 2015 2017 2016 2017 2016
 (In millions) (In millions)
Recognized stock compensation expense $2.0
 $4.8
 $5.3
 $9.1
 $3.2
 $2.0
 $5.8
 $5.3
Capitalized stock compensation cost for our oil and natural gas properties 0.4
 1.0
 1.2
 1.9
 0.4
 0.4
 0.8
 1.2
Tax benefit on stock based compensation 0.7
 1.7
 2.0
 3.4
 1.2
 0.7
 2.2
 2.0

The remaining unrecognized compensation cost related to unvested awards at June 30, 20162017 is approximately $10.9$17.4 million, of which $1.7$2.1 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.7 of aone year.

TheOur Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as to non-employee directors. A total of 4,500,0007,000,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan with 2,000,000 shares being the maximum number of shares that can be issued as "incentive stock options."


We did not grant any SARs or stock options during either of the three or six month periods ending June 30, 20162017 andor 20152016. The following tables showtable shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated.indicated:

 Three Months Ended Three Months Ended Three Months Ended Three Months Ended
 June 30, 2016 June 30, 2015 June 30, 2017 June 30, 2016
 
Time
Vested
 Performance Vested 
Time
Vested
 Performance Vested 
Time
Vested
 Performance Vested 
Time
Vested
 Performance Vested
Shares granted:                
Employees 
 
 
 
 14,000
 21,000
 
 
Non-employee directors 90,000
 
 25,848
 
 49,104
 
 90,000
 
 90,000
 
 25,848
 
 63,104
 21,000
 90,000
 
Estimated fair value (in millions):(1)
                
Employees $
 $
 $
 $
 $0.4
 $0.5
 $
 $
Non-employee directors 0.9
 
 0.9
 
 0.9
 
 0.9
 
 $0.9
 $
 $0.9
 $
 $1.3
 $0.5
 $0.9
 $
Percentage of shares granted expected to be distributed:                
Employees N/A
 N/A
 N/A
 N/A
 100% 87% N/A
 N/A
Non-employee directors 100% N/A
 100% N/A
 100% N/A
 100% N/A
_______________________
(1)Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)


 Six Months Ended Six Months Ended Six Months Ended Six Months Ended
 June 30, 2016 June 30, 2015 June 30, 2017 June 30, 2016
 
Time
Vested
 Performance Vested 
Time
Vested
 Performance Vested 
Time
Vested
 Performance Vested 
Time
Vested
 Performance Vested
Shares granted:                
Employees 486,578
 152,373
 576,361
 148,081
 475,799
 173,373
 486,578
 152,373
Non-employee directors 90,000
 
 25,848
 
 49,104
 
 90,000
 
 576,578
 152,373
 602,209
 148,081
 524,903
 173,373
 576,578
 152,373
Estimated fair value (in millions):(1)
                
Employees $2.6
 $0.8
 $18.5
 $5.1
 $11.8
 $4.5
 $2.6
 $0.8
Non-employee directors 0.9
 
 0.9
 
 0.9
 
 0.9
 
 $3.5
 $0.8
 $19.4
 $5.1
 $12.7
 $4.5
 $3.5
 $0.8
Percentage of shares granted expected to be distributed:                
Employees 94% 70% 94% 3% 95% 87% 94% 70%
Non-employee directors 100% N/A
 100% N/A
 100% N/A
 100% N/A
_______________________
(1)Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

The time vested restricted stock awards granted during the first six months of 20162017 and 20152016 are being recognized over a three yearthree-year vesting period. During the first two quarters of 2017 and the first quarter of 2016, there were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three yearthree-year vesting period based onsubject to the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected performance criteria at June 30, 2017, the participants are estimated to receive 74% of the 2017, 145% of the 2016, and 34% of the 2015 performance based shares. The CFTA performance measurement at June 30, 2017 was assessed to vest at target or 100%. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 20162017 awards for the first six months of 20162017 was $0.7$3.4 million.


NOTE 10 – DERIVATIVES

Commodity Derivatives

We have entered into 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 June 30, 20162017, our derivative transactions were comprised of the following hedges:

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

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

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


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

We have documented policies and procedures to monitor and control the use of derivative transactions. We do not engage in derivative transactions for speculative purposes. For our economic hedges anyAny changes in the fair value of our derivative transactions occurring before maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations.

At June 30, 2016, we had2017, the following derivatives were outstanding:
Term Commodity Contracted Volume 
Weighted Average 
Fixed Price
 Contracted Market
Jul’16Jul’17Dec’16Oct'17 Natural gas – swap 45,00070,000 MMBtu/day $2.5963.038 IF – NYMEX (HH)
Jan’17Nov’17 – Dec'17 Natural gas – swap 60,000 MMBtu/day $2.960 IF – NYMEX (HH)
Jan’18 – Dec'18 Natural gas – swap 10,00020,000 MMBtu/day $3.0253.013 IF – NYMEX (HH)
Jan’17Nov’17 – Dec'17 Natural gas – basis swap 20,000 MMBtu/day $(0.215) IF – NYMEX (HH)
Jan’18 – Mar'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Nov’18 – Dec'18 Natural gas – basis swap 10,000 MMBtu/day $(0.208) IF – NYMEX (HH)
Jul’16 – Dec'16Natural gas – collar42,000 MMBtu/day$2.40 - $2.88IF – NYMEX (HH)
Jan’17Jul’17 – Oct'17 Natural gas – collar 10,00020,000 MMBtu/day $2.752.88 - $2.95$3.10 IF – NYMEX (HH)
Jul’16Jul'17Dec'16Natural gas – three-way collar13,500 MMBtu/day$2.70 - $2.20 - $3.26IF – NYMEX (HH)
Jan’17 – Dec'17Oct'17 Natural gas – three-way collar 15,000 MMBtu/day $2.50 - $2.00 - $3.32 IF – NYMEX (HH)
Jul’16Nov’17Sep'16Dec'17 Crude oil – swap1,000 Bbl/day$48.45WTI – NYMEX
Jul’16 – Sep'16Crude oil – collar2,450 Bbl/day$44.44 - $52.46WTI – NYMEX
Oct’16 – Dec'16Crude oil – collar1,450 Bbl/day$47.50 - $56.40WTI – NYMEX
Jul’16 – Dec'16Crude oilNatural gas – three-way collar 700 Bbl/25,000 MMBtu/day $46.502.90 - $35.00$2.30 - $57.00$3.59 WTIIF – NYMEX (HH)
Jul’16Jan'18Dec'16Mar'18 
Crude oilNatural gas – three-way collar(1)
 700 Bbl/60,000 MMBtu/day $47.503.29 - $35.00$2.63 - $63.50$4.07 WTIIF – NYMEX (HH)
Jan’17Apr'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Jul’17 – Dec'17 Crude oil – three-way collar 7503,750 Bbl/day$49.79 - $39.58 - $60.98WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar1,000 Bbl/day $50.00 - $37.50$40.00 - $63.90$56.65 WTI – NYMEX
_______________________
(1)We pay our counterparty a premium, which can be and is being deferred until settlement.

After June 30, 2016, we entered into2017, the following derivatives:derivatives were entered into:
Term Commodity Contracted Volume 
Weighted Average 
Fixed Price
 Contracted Market
Jan’17Jan'18Oct'17Dec'18 Natural gasCrude oil swap500 Bbl/day$50.00WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar 10,000 MMBtu/1,000 Bbl/day $3.0045.00 - $3.24$35.00 - $55.50 IFWTI – 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   Derivative Assets
   Fair Value   Fair Value
 Balance Sheet Location June 30,
2016
 December 31,
2015
 Balance Sheet Location June 30,
2017
 December 31,
2016
   (In thousands)   (In thousands)
Commodity derivatives:        
Current Current derivative asset $
 $10,186
 Current derivative asset $3,948
 $
Long-term Non-current derivative asset 
 968
 Non-current derivative asset 689
 377
Total derivative assets $
 $11,154
 $4,637
 $377

   Derivative Liabilities   Derivative Liabilities
   Fair Value   Fair Value
 Balance Sheet Location June 30,
2016
 December 31,
2015
 Balance Sheet Location June 30,
2017
 December 31,
2016
   (In thousands)   (In thousands)
Commodity derivatives:        
Current Current derivative liability $9,646
 $
 Current derivative liability $1,036
 $21,564
Long-term Non-current derivative liability 3,420
 285
 Non-current derivative liability 
 415
Total derivative liabilities $13,066
 $285
 $1,036
 $21,979

All of 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 in our Unaudited Condensed Consolidated Balance Sheets.

EffectFollowing is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the three months ended June 30:
Derivatives Instruments 
Location of Loss Recognized in
Income on Derivative
 Amount of Loss Recognized in Income on Derivative 
Location of Gain (Loss) Recognized in
Income on Derivative
 
Amount of Gain 
(Loss) Recognized in Income on Derivative
   2016 2015   2017 2016
   (In thousands)   (In thousands)
Commodity derivatives 
Gain (loss) on derivatives (1)
 $(22,672) $(1,919) 
Gain (loss) on derivatives (1)
 $8,902
 $(22,672)
Total $(22,672) $(1,919) $8,902
 $(22,672)
_______________________
(1)Amounts settled during the 20162017 and 20152016 periods include gainsa loss of $5.1$0.4 million and $10.1a gain of $5.1 million, respectively.

EffectFollowing is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the six months ended June 30:
Derivatives Instruments 
Location of Gain (Loss) Recognized in
Income on Derivative
 Amount of Gain (Loss) Recognized in Income on Derivative 
Location of Gain (Loss) Recognized in
Income on Derivative
 Amount of Gain (Loss) Recognized in Income on Derivative
   2016 2015   2017 2016
   (In thousands)   (In thousands)
Commodity derivatives 
Gain (loss) on derivatives (1)
 $(11,743) $4,667
 
Gain (loss) on derivatives (1)
 $23,633
 $(11,743)
Total $(11,743) $4,667
 $23,633
 $(11,743)
_______________________
(1)Amounts settled during the 20162017 and 20152016 periods include gainsa loss of $12.2$1.6 million and $21.1a gain of $12.2 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-current other assets, is based on market quotes. The following is a summary of available-for-sale securities:

  Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value
  (In thousands)
Equity Securities:  
June 30, 2017 $830
 $32
 $
 $862
December 31, 2016 $
 $
 $
 $

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

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

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

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

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

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


The following tables set forth our recurring fair value measurements:
 June 30, 2016 June 30, 2017
 Level 2 Level 3 
Effect
of Netting
 Net Amounts Presented Level 1 Level 2 Level 3 
Effect
of Netting
 Net Amounts Presented
 (In thousands) (In thousands)
Financial assets (liabilities):                  
Commodity derivatives:                  
Assets $435
 $515
 $(950) $
 $
 $1,010
 $4,656
 $(1,029) $4,637
Liabilities (8,740) (5,276) 950
 (13,066) 
 (1,502) (563) 1,029
 (1,036)
Total commodity derivatives 
 (492) 4,093
 
 3,601
Equity securities 862
 
 
 
 862
 $(8,305) $(4,761) $
 $(13,066) $862
 $(492) $4,093
 $
 $4,463
 December 31, 2015 December 31, 2016
 Level 2 Level 3  
Effect
of Netting
 Net Amounts Presented Level 1 Level 2 Level 3 
Effect
of Netting
 Net Amounts Presented
 (In thousands) (In thousands)
Financial assets (liabilities):                  
Commodity derivatives:                  
Assets $2,794
 $10,145
 $(1,785) $11,154
 $
 $878
 $43
 $(544) $377
Liabilities (1,019) (1,051) 1,785
 (285) 
 (15,358) (7,165) 544
 (21,979)
 $1,775
 $9,094
 $
 $10,869
 $
 $(14,480) $(7,122) $
 $(21,602)

All of 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 any cash collateral with our counterparties and no collateral has been posted as of June 30, 2016.2017.

TheWe used the following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

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.


The following tables are reconciliationstable is a reconciliation of our level 3 fair value measurements: 
 Net Derivatives Net Derivatives
 Three Months Ended Six Months Ended Three Months Ended Six Months Ended
 June 30, June 30, June 30, June 30,
 2016 2015 2016 2015 2017 2016 2017 2016
 (In thousands) (In thousands)
Beginning of period $9,983
 $857
 $9,094
 $3,355
 $(602) $9,983
 $(7,122) $9,094
Total gains or losses (realized and unrealized):                
Included in earnings (1)
 (12,322) 111
 (6,334) 888
 5,214
 (12,322) 11,117
 (6,334)
Settlements (2,422) (761) (7,521) (4,036) (519) (2,422) 98
 (7,521)
End of period $(4,761) $207
 $(4,761) $207
 $4,093
 $(4,761) $4,093
 $(4,761)
Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period $(14,744) $(650) $(13,855) $(3,148)
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 $4,695
 $(14,744) $11,215
 $(13,855)
_______________________
(1)Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives.

The following table provides quantitative information about our Level 3 unobservable inputs at June 30, 2016:2017:
Commodity (1)
 Fair Value Valuation Technique Unobservable Input Range Fair Value Valuation Technique Unobservable Input Range
 (In thousands)       (In thousands)      
Oil collars $(151) Discounted cash flow Forward commodity price curve $0.07 - $5.31
Oil three-way collars $301
 Discounted cash flow Forward commodity price curve $0.00 - $6.35 $3,340
 Discounted cash flow Forward commodity price curve ($3.23) - $6.94
Natural gas collar $(3,253) Discounted cash flow Forward commodity price curve $0.00 - $0.90 $(180) Discounted cash flow Forward commodity price curve ($0.32) - $0.16
Natural gas three-way collars $(1,658) Discounted cash flow Forward commodity price curve $0.00 - $0.51 $933
 Discounted cash flow Forward commodity price curve ($0.42) - $0.60
 _______________________
(1)The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Based on ourOur valuation at June 30, 20162017, we determined reflected that the risk of non-performance by our counterparties was immaterial.


Fair Value of Other Financial Instruments

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

At June 30, 20162017, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short termshort-term nature.

Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at June 30, 20162017 and December 31, 20152016 was $236.0$164.9 million and $281.0$160.8 million, respectively. This debt would be classified as Level 2.

The carrying amounts of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of June 30, 20162017 and December 31, 20152016 were $639.1$641.2 million and $638.0640.1 million, respectively. We estimate the fair value of thesethe Notes using quoted marked prices at June 30, 20162017 and December 31, 20152016 werewas $505.4627.9 million and $455.5649.9 million, respectively. TheseThe Notes would be classified as Level 2.


Fair Value of Non-Financial Instruments

The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the Company’s AROs is presented in Note 7 – Asset Retirement Obligations.

NOTE 12 – COMMITMENTS AND CONTINGENCIES

We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. We also have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.Future minimum rental payments under the terms of the leases are approximately $3.5 million, $1.1 million, $0.4 million, $0.3 million, and $0.1 million in twelve month periods beginning July 1, 2017 (and through the end of 2021), respectively. Total rent expense incurred was $4.2 million and $6.2 million for the first six months of 2017 and 2016, respectively.

In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the five successive twelve month periods beginning July 1, 2017 (and through the end of 2021) are $6.2 million, $6.2 million, $6.2 million, $6.7 million, and $0.2 million. Total maintenance and interest remaining related to these leases are $6.8 million and $1.5 million, respectively at June 30, 2017. Annual payments, net of maintenance and interest, average $4.1 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value.

The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal. In any one year, these repurchases are limited to 20% of the units outstanding. We had no repurchases in the first six months of 2017 or 2016.

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 risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well.

For the next twelve months, we have committed to purchase approximately $3.9 million of new drilling rig components.

NOTE 13 – EQUITY

At-the-Market (ATM) Common Stock Program

On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms and conditions of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from

time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions that we may impose).
We are not obligated to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
As of June 30, 2017, we sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million.

Accumulated Other Comprehensive Income

Components of accumulated other comprehensive income were as follows for the three and six months ended June 30:
  2017 2016
  (In thousands)
Unrealized appreciation on securities, before tax $32
 $
Tax expense (12) 
Unrealized appreciation on securities, net of tax $20
 $

Changes in accumulated other comprehensive income by component, net of tax, for the three and six months ended June 30 are as follows:
  Net Gains on Equity Securities
  2017 2016
  (In thousands)
Beginning balance $
 $
Other comprehensive gain before reclassifications 20
 
Amounts reclassified from accumulated other comprehensive income 
 
Net current-period other comprehensive income 20
 
Balance at June 30 $20
 $


NOTE 1214 – 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, acquisition, 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 table providestables provide certain information about the operations of each of our segments:
  Three Months Ended June 30, 2017
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues:            
Oil and natural gas $83,173
 $
 $
 $
 $
 $83,173
Contract drilling 
 44,844
 
 
 (5,589) 39,255
Gas gathering and processing 
 
 63,111
 
 (14,958) 48,153
Total revenues 83,173
 44,844
 63,111
 
 (20,547) 170,581
Expenses:            
Operating costs:            
Oil and natural gas 33,941
 
 
 
 (1,183) 32,758
Contract drilling 
 32,452
 
 
 (5,213) 27,239
Gas gathering and processing 
 
 49,817
 
 (13,775) 36,042
Total operating costs 33,941
 32,452
 49,817
 
 (20,171) 96,039
Depreciation, depletion, and amortization 23,558
 13,769
 10,849
 1,904
 
 50,080
Total expenses 57,499
 46,221
 60,666
 1,904
 (20,171) 146,119
Total operating income (loss) (1)
 25,674
 (1,377) 2,445
 (1,904) (376)  
General and administrative expense 
 
 
 (8,713) 
 (8,713)
Gain on disposition of assets 168
 31
 44
 5
 
 248
Gain on derivatives 
 
 
 8,902
 
 8,902
Interest expense, net 
 
 
 (9,467) 
 (9,467)
Other 
 
 
 6
 
 6
Income (loss) before income taxes $25,842
 $(1,346) $2,489
 $(11,171) $(376) $15,438

  Three Months Ended June 30, 2016
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues:            
Oil and natural gas $69,190
 $
 $
 $
 $
 $69,190
Contract drilling 
 24,257
 
 
 
 24,257
Gas gathering and processing 
 
 56,533
 
 (11,675) 44,858
Total revenues 69,190
 24,257
 56,533
 
 (11,675) 138,305
Expenses:            
Oil and natural gas:            
Operating costs 35,555
 
 
 
 (2,224) 33,331
Depreciation, depletion, and amortization 30,411
 
 
 
 
 30,411
Impairment of oil and natural gas properties 74,291
 
 
 
 
 74,291
Contract drilling:            
Operating costs 
 19,254
 
 
 
 19,254
Depreciation 
 10,918
 
 
 
 10,918
Gas gathering and processing:            
Operating costs 
 
 41,832
 
 (9,451) 32,381
Depreciation and amortization 
 
 11,515
 
 
 11,515
Total expenses 140,257
 30,172
 53,347
 
 (11,675) 212,101
Total operating income (loss) (1)
 (71,067) (5,915) 3,186
 
 
 (73,796)
General and administrative expense 
 
 
 (8,382) 
 (8,382)
Gain (loss) on disposition of assets (324) 815
 
 (14) 
 477
Loss on derivatives 
 
 
 (22,672) 
 (22,672)
Interest expense, net 
 
 
 (10,606) 
 (10,606)
Other 
 
 
 1
 
 1
Income (loss) before income taxes $(71,391) $(5,100) $3,186
 $(41,673) $
 $(114,978)
_______________________
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairmentamortization and does not include general corporate expenses, (gain) lossgain on disposition of assets, lossgain on derivatives, interest expense, other income (loss), or income taxes.


 Three Months Ended June 30, 2015 Three Months Ended June 30, 2016
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
 (In thousands) (In thousands)
Revenues:                        
Oil and natural gas $107,256
 $
 $
 $
 $
 $107,256
 $69,190
 $
 $
 $
 $
 $69,190
Contract drilling 
 60,813
 
 
 (5,798) 55,015
 
 24,257
 
 
 
 24,257
Gas gathering and processing 
 
 69,163
 
 (16,987) 52,176
 
 
 56,533
 
 (11,675) 44,858
Total revenues 107,256
 60,813
 69,163
 
 (22,785) 214,447
 69,190
 24,257
 56,533
 
 (11,675) 138,305
Expenses:                        
Oil and natural gas:            
Operating costs 47,179
 
 
 
 (1,207) 45,972
Operating costs:            
Oil and natural gas 35,555
 
 
 
 (2,224) 33,331
Contract drilling 
 19,254
 
 
 
 19,254
Gas gathering and processing 
 
 41,832
 
 (9,451) 32,381
Total operating costs 35,555
 19,254
 41,832
 
 (11,675) 84,966
Depreciation, depletion, and amortization 68,101
 
 
 
 
 68,101
 30,411
 10,918
 11,515
 34
 
 52,878
Impairment of oil and natural gas properties 410,536
 
 
 
 
 410,536
Contract drilling:            
Operating costs 
 41,746
 
 
 (5,261) 36,485
Depreciation 
 13,265
 
 
 
 13,265
Impairment of contract drilling properties 
 8,314
 
 
 
 8,314
Gas gathering and processing:            
Operating costs 
 
 56,372
 
 (15,780) 40,592
Depreciation and amortization 
 
 10,848
 
 
 10,848
Impairments 74,291
 
 
 
 
 74,291
Total expenses 525,816
 63,325
 67,220
 
 (22,248) 634,113
 140,257
 30,172
 53,347
 34
 (11,675) 212,135
Total operating income (loss)(1)
 (418,560) (2,512) 1,943
 
 (537) (419,666) (71,067) (5,915) 3,186
 (34) 
  
General and administrative expense 
 
 
 (9,624) 
 (9,624) 
 
 
 (8,348) 
 (8,348)
Gain (loss) on disposition of assets 
 (50) 465
 
 
 415
 (324) 815
 
 (14) 
 477
Loss on derivatives 
 
 
 (1,919) 
 (1,919) 
 
 
 (22,672) 
 (22,672)
Interest expense, net 
 
 
 (7,956) 
 (7,956) 
 
 
 (10,606) 
 (10,606)
Other 
 
 
 24
 
 24
 
 
 
 1
 
 1
Income (loss) before income taxes $(418,560) $(2,562) $2,408
 $(19,475) $(537) $(438,726) $(71,391) $(5,100) $3,186
 $(41,673) $
 $(114,978)
_______________________
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes.


 Six Months Ended June 30, 2016 Six Months Ended June 30, 2017
 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
 (In thousands) (In thousands)
Revenues:                        
Oil and natural gas $127,464
 $
 $
 $
 $
 $127,464
 $170,771
 $
 $
 $
 $
 $170,771
Contract drilling 
 62,967
 
 
 
 62,967
 
 82,029
 
 
 (5,589) 76,440
Gas gathering and processing 
 
 105,578
 
 (21,520) 84,058
 
 
 129,575
 
 (30,481) 99,094
Total revenues 127,464
 62,967
 105,578
 
 (21,520) 274,489
 170,771
 82,029
 129,575
 
 (36,070) 346,305
Expenses:                        
Oil and natural gas:            
Operating costs 70,361
 
 
 
 (3,684) 66,677
Operating costs:            
Oil and natural gas 64,267
 
 
 
 (2,305) 61,962
Contract drilling 
 61,679
 
 
 (5,213) 56,466
Gas gathering and processing 
 
 101,922
 
 (28,176) 73,746
Total operating costs 64,267
 61,679
 101,922
 
 (35,694) 192,174
Depreciation, depletion, and amortization 62,243
 
 
 
 
 62,243
 45,084
 26,616
 21,667
 3,645
 
 97,012
Impairment of oil and natural gas properties 112,120
 
 
 
 
 112,120
Contract drilling:            
Operating costs 
 47,352
 
 
 
 47,352
Depreciation 
 23,113
 
 
 
 23,113
Gas gathering and processing:            
Operating costs 
 
 81,283
 
 (17,836) 63,447
Depreciation and amortization 
 
 22,974
 
 
 22,974
Total expenses 244,724
 70,465
 104,257
 
 (21,520) 397,926
 109,351
 88,295
 123,589
 3,645
 (35,694) 289,186
Total operating income (loss)(1)
 (117,260) (7,498) 1,321
 
 
 (123,437) 61,420
 (6,266) 5,986
 (3,645) (376)  
General and administrative expense 
 
 
 (17,097) 
 (17,097) 
 
 
 (17,667) 
 (17,667)
Gain (loss) on disposition of assets (324) 1,316
 (302) (21) 
 669
Loss on derivatives 
 
 
 (11,743) 
 (11,743)
Gain on disposition of assets 177
 38
 44
 813
 
 1,072
Gain on derivatives 
 
 
 23,633
 
 23,633
Interest expense, net 
 
 
 (20,223) 
 (20,223) 
 
 
 (18,863) 
 (18,863)
Other 
 
 
 (14) 
 (14) 
 
 
 9
 
 9
Income (loss) before income taxes $(117,584) $(6,182) $1,019
 $(49,098) $
 $(171,845) $61,597
 $(6,228) $6,030
 $(15,720) $(376) $45,303
_______________________
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.


  Six Months Ended June 30, 2016
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues:            
Oil and natural gas $127,464
 $
 $
 $
 $
 $127,464
Contract drilling 
 62,967
 
 
 
 62,967
Gas gathering and processing 
 
 105,578
 
 (21,520) 84,058
Total revenues 127,464
 62,967
 105,578
 
 (21,520) 274,489
Expenses:            
Operating costs:            
Oil and natural gas 70,361
 
 
 
 (3,684) 66,677
Contract drilling 
 47,352
 
 
 
 47,352
Gas gathering and processing 
 
 81,283
 
 (17,836) 63,447
Total operating costs 70,361
 47,352
 81,283
 
 (21,520) 177,476
Depreciation, depletion, and amortization 62,243
 23,113
 22,974
 138
 
 108,468
Impairments 112,120
 
 
 
 
 112,120
Total expenses 244,724
 70,465
 104,257
 138
 (21,520) 398,064
Total operating income (loss)(1)
 (117,260) (7,498) 1,321
 (138) 
  
General and administrative expense 
 
 
 (16,959) 
 (16,959)
Gain (loss) on disposition of assets (324) 1,316
 (302)
(21) 
 669
Loss on derivatives 
 
 
 (11,743) 
 (11,743)
Interest expense, net 
 
 
 (20,223) 
 (20,223)
Other 
 
 
 (14) 
 (14)
Income (loss) before income taxes $(117,584) $(6,182) $1,019
 $(49,098) $
 $(171,845)
_______________________
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes.


  Six Months Ended June 30, 2015
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues:            
Oil and natural gas $213,325
 $
 $
 $
 $
 $213,325
Contract drilling 
 165,751
 
 
 (15,659) 150,092
Gas gathering and processing 
 
 142,967
 
 (36,838) 106,129
Total revenues 213,325
 165,751
 142,967
 
 (52,497) 469,546
Expenses:            
Oil and natural gas:            
Operating costs 93,560
 
 
 
 (2,377) 91,183
Depreciation, depletion, and amortization 145,219
 
 
 
 
 145,219
Impairment of oil and natural gas properties 811,129
 
 
 
 
 811,129
Contract drilling:            
Operating costs 
 100,443
 
 
 (12,212) 88,231
Depreciation 
 28,278
 
 
 
 28,278
Impairment of contract drilling properties 
 8,314
 
 
 
 8,314
Gas gathering and processing:            
Operating costs 
 
 119,228
 
 (34,461) 84,767
Depreciation and amortization 
 
 21,542
 
 
 21,542
Total expenses 1,049,908
 137,035
 140,770
 
 (49,050) 1,278,663
Total operating income (loss) (1)
 (836,583) 28,716
 2,197
 
 (3,447) (809,117)
General and administrative expense 
 
 
 (18,994) 
 (18,994)
Gain on disposition of assets 
 495
 465
 
 
 960
Gain on derivatives 
 
 
 4,667
 
 4,667
Interest expense, net 
 
 
 (15,196) 
 (15,196)
Other 
 
 
 22
 
 22
Income (loss) before income taxes $(836,583) $29,211
 $2,662
 $(29,501) $(3,447) $(837,658)
_______________________
(1)Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.


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. We haveMD&A is organized MD&A into the following sections: 

General;
Business Outlook;
Executive Summary;
Financial Condition and Liquidity;
New Accounting Pronouncements; and
Results of Operations.

Please read the information in our most recent Annual Report on Form 10-K in connection with your review of the information below as well as our unaudited condensed consolidated financial statements and related notes.

Unless otherwise indicated or required by the content, when 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.

General

We operate, manage, and analyze the results of our operations through that of 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 own account.oil and natural gas segment.
Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account.oil and natural gas segment.

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, and natural gas, and NGLs, as well as, the demand for our drilling rigs which, in turn, influences the amounts we can charge for those drilling rigs. While our operations are located within the United States, events outside the United States affect us and our industry.

Deteriorating commodity prices worldwide during the past 20 or so monthsseveral years brought about significant and adverse changes affectingto our industry and us. These lower commodity prices caused us (and otherAs a result we reduced or stopped, for a period of time, our oil and natural gas companies) to reduce (or even stop) our level ofsegment's drilling activity and spending. Whenactivity. Industry wide reductions in drilling activity and spending decline for extended periods of timealso tends to reduce the rates for and the number of our drilling rigs working also tend to decline.that we can work. In addition, sustained lower commodity prices can impact the liquidity condition of some of our industry partners and customers, which, in turn, could limit their ability to meet their financial obligations to us.

It is uncertain how long the current depressedDuring 2016, commodity prices will continue. As noted elsewherebegan to improve. In the fourth quarter of 2016, our oil and natural gas segment began using two of our drilling rigs and has continued using them during the first six months of 2017. Our contract drilling segment completed the construction and contracted the ninth and tenth BOSS drilling rigs in the fourth quarter of 2016 and the second quarter of 2017, respectively. Our drilling rig segment's rig utilization increased from 16 drilling rigs working as of June 30, 2016, to 33 drilling rigs working as of June 30, 2017. The extent and duration of this report, those prices are subject to a number of factors most of which we cannot control.improvement remains uncertain.


The impact on our business and financial results from the reduction in oil, NGLs, and natural gas prices has had a number of consequences for us including:(although, as noted, we are starting to see some improvements). Below are some of those consequences:

We incurred non-cash ceiling test write-downs in the first sixnine months of 2016 of $112.1$161.6 million ($69.8100.6 million net of tax). We did not have a write-down in the fourth quarter of 2016 or the first two quarters of 2017. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax

attributes. Subject to these factors and inherent limitations,uncertainties, if we hold these same factors constant as they existed on July 1, 2016at June 30, 2017 and only adjustedadjust the 12-month average price to an estimated secondthird quarter ending average (holding July 20162017 prices constant for the remaining two months of the third quarter of 2016)2017), our forward looking expectation is that we wouldwill not expect to recognize an impairment in the third quarter of 2016. Commodity2017. But commodity prices (and other factors) remain volatile and have recently trended downward and should that trend continue itthey could negatively impact the 12-month average price andresulting in the potential for an impairment in the third quarter.future.
We have reduced the number of gross wells we plan to drillour oil and natural gas segment drilled in 2016 by approximately 57-66%64% from the number drilled in 2015 due to our reduced cash flow resultingflow. For 2017, we plan to increase the number of gross wells drilled by approximately 67-90% (depending on future commodity prices) from lower commodity prices.the number of wells drilled in 2016.
Several ofThe decline in drilling by our drilling rig customers significantly reduced their drilling budgets, which have reduced the average utilization of our drilling rig fleet. At December 31, 2015, we had 26 drilling rigs operating. In 2016, utilization continued downward bottoming out in May 2016 at 13 operating drilling rigs. After May commodity prices began improving for the remainder of the year and at July 22,we exited 2016 that number was 16. Wewith 21 active rigs. As of June 30, 2017, we had 33 drilling rigs operating (an improvement of 57% over the end of the year). Operators have been increasing drilling, but the extent of further increases remain uncertain. During the second quarter of 2017, we completed the construction of our tenth BOSS drilling rig and all of our BOSS drilling rigs are starting to see a small increase in rig activity in the third quarter.under contract.
Due to the low NGLs prices, we are operatingcontinue to operate most of our mid-stream processing facilities in full ethane rejection mode which reduces the amount of liquids sold. As long as NGLs prices continue to beremain depressed, we expect to continue operating in full ethane rejection mode. As low commodity prices continue, we expect the reductions in drilling activity around our systems will reduce the number of new wells available to connect to our systems thus resulting in lower processed volumes
Also, as production from connected wells naturally decline.
Under the third amendment to our credit agreement entered intonoted elsewhere, beginning on April 8, 2016,4, 2017, we began an at-the-market offering for the lenders decreasedsale of shares of our borrowing basecommon stock. The offering allows us to sell shares, from $550.0time to time, up to an aggregate of $100 million to $475.0in gross proceeds. As of June 30, 2017, we sold 787,547 shares for $18.6 million, net of offering costs of $0.4 million. Our commitmentApproximately $81.0 million remain available for sale under the program. Net proceeds from the offering will be used to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit agreement also decreased from $500.0 million to $475.0 million. At July 22, 2016, borrowings were $238.6 million. We believe our liquidity is adequate to carry out our 2016 capital plans.facility, and general corporate purposes.

We have reduced our total 2016 capital budget by a rangeOn April 3, 2017, we closed an acquisition of approximately 59-65% as compared to 2015, excluding acquisitions and ARO liability. The budget is designed to keep our capital expenditures below our anticipated cash flow and proceeds from any non-core asset sales and is based on realized prices for the year of $34.57 per barrel of oil, $8.01 per barrel of NGLs, and $2.24 per Mcf of natural gas. We may periodically adjust our budget for various reasons including changes in commodity prices and industry conditions. Funding for the budget will come primarily from our cash flow, possible non-core asset sales, and, if necessary, borrowings under our credit agreement.

In response to lower commodity prices we did the following during the first six months of 2016:

Consolidated from five to two the number of divisions within our drilling segment further reducing the costs associated with operating the divisions.
Designed the higher end of our 2016 exploration and production segment budget so the majority of those proposed expenditures would be in the latter part of the year allowing us to take into account future commodity price movement before we actually incur those expenditures.
Implemented certain reductions in our office and field workforces to account for the reduction in our operating activities as well as reducing the compensation paid to drilling personnel.
Through June 30, 2016, we have sold non-core oil and natural gas properties forassets from an unrelated third party. The acquisition includes approximately $43.6 million with most47 proved developed producing wells and 8,300 net acres primarily in Grady and Caddo Counties in western Oklahoma. The preliminary adjusted value of the proceeds being usedconsideration given was $54.0 million. This acquisition is subject to pay down borrowings under our bank credit agreement.certain post-closing adjustments. The effective date of this acquisition is January 1, 2017.

Executive Summary

Oil and Natural Gas

Second quarter 20162017 production from our oil and natural gas segment was 4,359,0003,852,000 barrels of oil equivalent (Boe), an increase of 2% over the first quarter of 2017 and a decrease of 3%12% from the second quarter of 2016, respectively. The increase over the first quarter of 2017 was from acquired wells and 14%new wells drilled in the first six months of 2017. The decrease from the second quarter of 2016 was primarily due to the continued production decline of existing wells and reduced drilling activity between the periods. Second quarter 2017 production was also negatively affected by approximately 94,000 Boe due to third party gas processing outages and the delay of several fracture stimulation jobs from early May until early June.

Second quarter 2017 oil and natural gas revenues decreased 5% from the first quarter of 20162017 and increased 20% over the second quarter of 2015, respectively. This2016. The decrease was primarily due to natural declines in production with minimal replacement in production from new wells due to our reduced drilling activity resulting from lower commodity prices.

Second quarter 2016 oil and natural gas revenues increased 19% over the first quarter of 2016 and decreased 36% from the second quarter of 2015.2017 was due primarily to lower commodity prices partially offset by higher production volumes. The increase over firstthe second quarter of 2016 was due primarily to higher oil and NGLs prices offset partially from lower production volumes and lower natural gas prices. The decrease from the second quarter of 2015 was due primarily to lower commodity prices and to a lesser extent frompartially offset by lower production volumes.


Our oil prices for the second quarter of 2016 increased 28% over the first quarter of 2016 and decreased 25% from the second quarter of 2015. Our NGLs prices increased 73% over the first quarter of 2016 and decreased 6% from the second quarter of 2015. Our natural gas prices2017 decreased 4% from the first quarter of 20162017 and decreased 33% fromincreased 13% over the second quarter of 2015.2016. Our NGLs prices decreased 16% from the first quarter of 2017 and increased 31% over the second

quarter of 2016. Our natural gas prices decreased 9% from the first quarter of 2017 and increased 36% over the second quarter of 2016.

Operating cost per Boe produced for the second quarter of 20162017 increased 4%10% and 11% over the first quarter of 20162017 and decreased 16% from the second quarter of 2015.2016, respectively. The increase over the first quarter of 2017 was primarily due to an increase in saltwater disposal expense and increased production taxes after receiving a higher amount of tax refunds. The increase over the second quarter of 2016 was primarily due to higher grosslower production taxes due to fewer gross production tax credits. The decrease from the second quarter of 2015 was primarily due tovolumes partially offset by lower lease operating expenses, saltwater disposal expense, and general and administrative expenses.

At June 30, 2016,2017, we had the followingthese derivatives outstanding:
Term Commodity Contracted Volume 
Weighted Average 
Fixed Price
 Contracted Market
Jul’16Jul’17Dec’16Oct'17 Natural gas – swap 45,00070,000 MMBtu/day $2.5963.038 IF – NYMEX (HH)
Jan’17Nov’17 – Dec'17 Natural gas – swap 60,000 MMBtu/day $2.960 IF – NYMEX (HH)
Jan’18 – Dec'18 Natural gas – swap 10,00020,000 MMBtu/day $3.0253.013 IF – NYMEX (HH)
Jan’17Nov’17 – Dec'17 Natural gas – basis swap 20,000 MMBtu/day $(0.215) IF – NYMEX (HH)
Jan’18 – Mar'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Nov’18 – Dec'18 Natural gas – basis swap 10,000 MMBtu/day $(0.208) IF – NYMEX (HH)
Jul’16 – Dec'16Natural gas – collar42,000 MMBtu/day$2.40 - $2.88IF – NYMEX (HH)
Jan’17Jul’17 – Oct'17 Natural gas – collar 10,00020,000 MMBtu/day $2.752.88 - $2.95$3.10 IF – NYMEX (HH)
Jul’16Jul'17Dec'16Natural gas – three-way collar13,500 MMBtu/day$2.70 - $2.20 - $3.26IF – NYMEX (HH)
Jan’17 – Dec'17Oct'17 Natural gas – three-way collar 15,000 MMBtu/day $2.50 - $2.00 - $3.32 IF – NYMEX (HH)
Jul’16Nov’17Sep'16Dec'17 Crude oil – swap1,000 Bbl/day$48.45WTI – NYMEX
Jul’16 – Sep'16Crude oil – collar2,450 Bbl/day$44.44 - $52.46WTI – NYMEX
Oct’16 – Dec'16Crude oil – collar1,450 Bbl/day$47.50 - $56.40WTI – NYMEX
Jul’16 – Dec'16Crude oilNatural gas – three-way collar 700 Bbl/25,000 MMBtu/day $46.502.90 - $35.00$2.30 - $57.00$3.59 WTIIF – NYMEX (HH)
Jul’16Jan'18Dec'16Mar'18 
Crude oilNatural gas – three-way collar(1)
 700 Bbl/60,000 MMBtu/day $47.503.29 - $35.00$2.63 - $63.50$4.07 WTIIF – NYMEX (HH)
Jan’17Apr'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Jul’17 – Dec'17 Crude oil – three-way collar 7503,750 Bbl/day$49.79 - $39.58 - $60.98WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar1,000 Bbl/day $50.00 - $37.50$40.00 - $63.90$56.65 WTI – NYMEX
_______________________
(1)We pay our counterparty a premium, which can be and is being deferred until settlement.

After June 30, 2016, we entered into2017, the following derivatives:derivatives were entered into:
Term Commodity Contracted Volume 
Weighted Average 
Fixed Price
 Contracted Market
Jan’17Jan'18Oct'17Dec'18 Natural gasCrude oil swap500 Bbl/day$50.00WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar 10,000 MMBtu/1,000 Bbl/day $3.0045.00 - $3.24$35.00 - $55.50 IFWTI – NYMEX (HH)

For the six months ended June 30, 2016,2017, we completed drilling 1319 gross wells (7.65(8.21 net wells). For all of 2016,2017, we plan to participate in the drilling of approximately 20-2535 to 40 gross wells. Excluding acquisitions and ARO liability, our estimated 20162017 capital expenditures for this segment range from $109.0 to $131.0are approximately $197.0 million. Our current 20162017 production guidance is approximately 16.916.0 to 17.416.5 MMBoe, a decrease of 13%4% to 16%7% from 2015,2016, although actual results continue to be subject to many factors.


Contract Drilling

The average number of drilling rigs we operated in the second quarter of 20162017 was 13.528.8 compared to 20.625.5 and 30.713.5 in the first quarter of 20162017 and the second quarter of 2015,2016, respectively. Late in the fourth quarter of 2014, the number of our drilling rigs operating started to decline and has continued to decline through the first six months of 2016 because of lower commodity prices and operators reducing their drilling budgets. As of June 30, 2016, 162017, 33 of our drilling rigs were operating.

Revenue for the second quarter of 2016 decreased 37%2017 increased 6% and 56% from62% over the first quarter of 20162017 and the second quarter of 2015,2016, respectively. The decreasesincreases were primarily due primarily to feweran increase in drilling rigs operating.operating partially offset by lower dayrates between the second quarter of 2017 and the second quarter of 2016.

Dayrates for the second quarter of 20162017 averaged $18,585,$15,962, a 1% increase over the first quarter of 20162017 and a 7%14% decrease from the second quarter of 2015.2016. The increase over the first quarter of 2017 was primarily due to increased demand. The decrease from the second quarter of 20152016 was primarily due to downward pressure on dayrates fromdue to lower demand.

Operating costs for the second quarter of 20162017 decreased 31% and 47%7% from the first quarter of 20162017 and increased 41% over the second quarter of 2015, respectively.2016. The decreases weredecrease from the first quarter of 2017 was primarily due to less new rig activation costs. The

increase over the second quarter of 2016 was due primarily to fewermore drilling rigs operating.operating partially offset by decreased per day cost.

Almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The continued lowimproved commodity pricespricing for oil and natural gas that began during the second half of 2016 has changedincreased demand for drilling rigs. These factors affectOur drilling rig count bottomed out at 13 drilling rigs operating during the second quarter of 2016, but increased to 21 drilling rigs operating at the end of 2016. Our drilling rig count continued to increase during the first half of 2017 ending at 33 operating drilling rigs. The future demand for and mix of the typeavailability of drilling rigs used by our customers andto meet that demand will impactaffect our future dayrates.

As of June 30, 2016, we had fiveWe have 15 term drilling contracts with original terms ranging from six months to threetwo years. OneSeven are up for renewal in the third quarter of these contracts2017, six in the fourth quarter of 2017, one is up for renewal in the fourth quarter of 20162018, and four are up for renewalone in 2017.2019. Term contracts may contain a fixed rate for the duration ofduring the contract or provide for rate adjustments within a specific range from the existing rate. Some operators who hadwith signed term contracts have opted to release the drilling rig and pay an early termination penalty for the remaining term of the contract. During the second quarterfirst six months of 2016,2017, we recorded $0.4$0.8 million inof early termination fees compared to $2.6$3.0 million in the first quartersix months of 20162016.

All ten of our existing BOSS drilling rigs are under contract. Construction was completed on our tenth BOSS drilling rig and $1.6 millionthe rig was placed into service late in the second quarter of 2015.

As of June 30, 2016, sevenquarter. We also have contracted and placed into service three of our eight BOSSstacked SCR drilling rigs were under contract. Currently, we do notin our Mid-Continent division during the second quarter. One SCR drilling rig was upgraded, one was relocated from our Rocky Mountain division, and the third SCR rig required no modifications. We have any contractstwo additional stacked SCR drilling rigs returning to build additional BOSS drilling rigs.service in the third quarter. Both in our Mid-Continent division. One is being relocated from our Rocky Mountain division. Our anticipated 2016estimated 2017 capital expenditures for this segment rangeare approximately $28.0 million.

Competition to keep qualified labor continues to be an issue we face in this segment. We do not believe this shortage of qualified labor will keep us from $9.0 millionworking additional drilling rigs, but it could cause some delays in the time to $11.0 million, an 87-89% decrease from 2015.crew new drilling rigs. Beginning in third quarter 2017, we increased compensation for certain drilling rig personnel.

Mid-Stream

Second quarter 20162017 liquids sold per day increased 2%6% over the first quarter of 20162017 and decreased 11%1% from the second quarter of 2015.2016, respectively. The increase over the first quarter of 20162017 was due to recovering more liquidsincreased volumes at certainour processing facilities. The decrease from the second quarter of 20152016 was primarily due to less volume available to process at our plants. For the second quarter of 2016,2017, gas processed per day decreased 3% fromincreased 7% over the first quarter of 20162017 and decreased 13%16% from the second quarter of 2015.2016. The decreases wereincrease over the first quarter of 2017 was primarily due to higher volumes at our Cashion facility from an offload and more drilling activity at our Hemphill facility. The decrease from the second quarter of 2016 was primarily due to declines in existing volumes, and fewer new wells connected.connected, and losing an offload volume at our Hemphill facility in mid-2016. For the second quarter of 2016,2017, gas gathered per day increased 15% overdecreased 2% and 13% from the first quarter of 20162017 and increased 21% over the second quarter of 2015.2016, respectively. The increasesdecreases were primarily from additional wells addeddue to declining volume on our Pittsburgh Mills gathering system.Appalachian systems and losing an offload volume at our Hemphill facility in mid-2016.

NGLs prices in the second quarter of 2016 increased 38% over2017 decreased 12% from the prices received in the first quarter of 20162017 and were essentially unchanged fromincreased 9% over the prices received in the second quarter of 2015.2016. Because certain of the contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts–under which we receive a share of the proceeds from the sale of the NGLs–our revenues from those commodity-based contracts fluctuate based on the price of NGLs.

Total operating cost for our mid-stream segment for the second quarter of 2016 increased2017 decreased 4% overfrom the first quarter of 20162017 and decreased 20% fromincreased 11% over the second quarter of 2015.2016. Second quarter of 20162017 costs were higherlower than the first quarter of 2017 primarily due to lower gas purchase prices partially offset by increased purchase volumes. The increase over the second quarter of 2016 was primarily due to higher gas purchase prices whilepartially offset by lower purchase volumes and lower field direct expenses.

In the Appalachian region, our Pittsburgh Mills gathering system, in Allegheny and Butler counties, continues to produce consistent financial results. Our average gathered volume for the second quarter of 2016 versus second2017 is approximately 133 MMcf per day. We connected the new Allen well pad in May and it included five new wells. And we are constructing a pipeline to connect the Miller well pad, which will be the next pad connected to our system. The Miller pad will include seven new wells and we anticipate it will be ready to flow in the third quarter of 2015 was lower due2018. Also, we anticipate several in-fill wells to lower gas purchase pricesbe drilled and lower purchase volumes along with lower general and administrative and field direct expenses.connected to our system in the first half of 2018.


At our Hemphill Texas system, our total throughput volume averaged 57.5 MMcf per day for the second quarter of 2016, our total throughput volume averaged 69.3 MMcf per day2017 and our total production of natural gas liquids was approximately 172,200142,000 gallons per day. At this processing facility we have the capacity to process 135 MMcf per day through three processing skids. During the second quarter, we connected one new- long lateral well to this system.

At our Bellmon processing facility located in the Mississippian play in north central Oklahoma, our total throughput volume averaged approximately 34 MMcf per day for the second quarter of 2016. Additionally, during the second quarter, we

increased our natural gas liquids volume to approximately 130,800 gallons per day. After minor modifications to our gathering system, we have been receiving additional volumes from third party producers since the first of this year. During the first six months of 2016, we connected 15 additional wells to this gathering system. At this processing facility we have two processing skids available that provide totalTotal processing capacity of 90 MMcf per day.

At our Segno gatheringat this facility located Southeast Texas, our average transported volume increased to over 90 MMcf per day for the second quarter of 2016. Since the first of this year, we connected three new wells to this gathering system. With the completion of the GAP pipeline extension project, our total gathering capacity has increased to 120 MMcf per day for this system.

In the Appalachian region, at our Pittsburgh Mills gathering system, our average throughput volume continues to increase. During the second quarter of 2016 the total throughput volume increased to approximately 142.5 MMcf per day. Since the beginning of this year we have connected three new well pads with a total of 12 new wells to this gathering system. In June, we connected the Thompson well pad which included two new wells. The Thompson well pad is located on the northern end of our system and delivers gas into NiSource’s Big Pine system. We have completed construction of a pipeline to connect our next well pad which is the Belo pad. There are six wells located on this pad and it was connected and began flowing gas in July.

Also in the Appalachian area at our Snow Shoe gathering system, since the first of this year, we have connected three well pads that have a total of six wells. Our average throughput volume for the second quarter of 2016 has increased to approximately 14135 MMcf per day. During the second quarter, we connected one new well padand since the beginning of 2017, we connected two new wells to this processing facility. Our oil and gas segment continues to operate a rig and we anticipate connecting four more wells in the third quarter.  

At our Cashion processing facility in central Oklahoma, our total throughput volume for the second quarter of 2017 averaged approximately 37.8 MMcf per day and our total production of natural gas liquids increased to approximately 207,000 gallons per day. Total processing capacity for this facility remains at approximately 45 MMcf per day. In the first six months of 2017, we connected one new well and completed a construction project that had threeallows us to bring additional gas to this processing plant from a third party producer. This new producer will deliver fee-based volume to us for five years or will pay a shortfall fee settled annually. And we are constructing a new pipeline extension which will allow us to connect a new producer to our system. Construction of this pipeline is underway and we expect to connect the first well to our system in the thrid quarter of this year. 

At our Bellmon processing facility in the Mississippian play in north central Oklahoma, we connected six new wells which began flowing in April.the second quarter of 2017 and our total throughput volume averaged approximately 27 MMcf per day. Total natural gas liquids averaged approximately 137,700 gallons per day while operating in ethane recovery mode at this facility. Total processing capacity at this system is approximately 90 MMcf per day.

At our Segno gathering facility in Southeast Texas, gathered volume for the second quarter of 2017 averaged approximately 79.2 MMcf per day. At this facility, we have increased our gathering and dehydration capacity to approximately 120 MMcf per day. We have completed preliminary construction of the Snow Shoe compressor station but we will not complete the compressor station until compression services are required.connected one new well to this system in 2017.

Our estimated 20162017 capital expenditures for this segment range from $22.0 million to $24.0are approximately $16.0 million.

Financial Condition and Liquidity

Summary

Our financial condition and liquidity depends on the cash flow from our operations and borrowings under our credit agreement. The amount of ourOur 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 currently believe we will have sufficientenough cash flow and liquidity to meet our obligations and remain in compliance with our debt covenants for the next twelve months. Our ability to meet our debt covenants (under our credit agreement as well asand our 2011 Indenture) and our capacity to incur additional indebtedness will depend on our future performance, which in turn will be affected by financial, business, economic, regulatory, and other factors. For example, if we experience lower oil, natural gas, and NGLs prices since the last borrowing base determination under our credit agreement, it could result incause a reduction of the borrowing base and therefore reduce or limit our ability to incur indebtedness. As a result, weWe monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues, and work, where possible, with our lenders to address those issues if any, ahead of time.

As part of our efforts to manage liquidity risks, we have lowered our capital expenditures budget, focused our drilling program on our highest return plays, and continue to explore opportunities to divest non-core assets and properties. During the first six months, we sold non-core oil and gas properties for approximately $43.6 million using most of the proceeds to pay down borrowings under our bank credit agreement. If necessary, we could sell other non-core assets and use the proceeds to further reduce our outstanding borrowings.


 Six Months Ended June 30, 
%
Change (1)
 Six Months Ended June 30, 
%
Change
 2016 2015  2017 2016 
 (In thousands except percentages) (In thousands except percentages)
Net cash provided by operating activities $132,716
 $257,606
 (48)% $117,055
 $132,716
 (12)%
Net cash used in investing activities (77,386) (366,442) (79)% (142,833) (77,386) 85 %
Net cash (used in) provided by financing activities (55,191) 108,626
 (151)%
Net cash provided by (used in) financing activities 25,734
 (55,191) 147 %
Net increase (decrease) in cash and cash equivalents $139
 $(210)   $(44) $139
  

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 impacted by changes in working capital.

Net cash provided by operating activities in the first six months of 20162017 decreased by $124.9$15.7 million fromas compared to the first six months of 2015.2016. The decrease was the result of lower revenues resulting from lower commodity prices, lower drilling rig utilization, and by changes in operating assets and liabilities related to the timing of cash receipts and disbursements.disbursements partially offset by higher profit margins in all three segments.

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 decreasedincreased by $289.1$65.4 million for the first six months of 20162017 compared to the first six months of 2015.2016. The change was due primarily to a decreasean increase in capital expenditures due to an oil and an increasegas property acquisition, the restarting of our contract drilling program in 2017, the construction of two new BOSS drilling rigs, and a decrease in the proceeds received from the disposition of assets. See additional information on capital expenditures below under Capital Requirements.

Cash Flows from Financing Activities

Cash flows (used in) provided by financing activities decreasedincreased by $163.8$80.9 million for the first six months of 20162017 compared to the first six months of 2015. This decrease2016. The increase was primarily due to the payback ofan increase in borrowings under our credit agreement.agreement, proceeds from the ATM common stock program, and an increase in book overdrafts in 2017 after we paid down debt in the first six months of 2016.

At June 30, 20162017, we had unrestricted cash totaling $1.0$0.8 million and had borrowed $236.0$164.9 million of the $475.0 million we had elected to then have available under our credit agreement. Our credit agreement is used primarily for working capital and capital expenditures.

The following is a summary of certain financial information as of June 30, 20162017 and 20152016 and for the six months ended June 30, 20162017 and 20152016:
  June 30, 
%
Change(1)
  2016 2015 
  (In thousands except percentages)
Working capital $(57,463) $(11,366) NM
Long-term debt less debt issuance costs $875,051
 $917,447
 (5)%
Shareholders’ equity $1,211,221
 $1,823,600
 (34)%
Net loss $(113,285) $(522,743) (78)%
_______________________
(1)NM - A percentage calculation is not meaningful due to a zero-value denominator or a percentage greater than 200.


The following table summarizes certain operating information:
  Six Months Ended  
  June 30, 
%
Change
  2016 2015 
Oil and Natural Gas:      
Oil production (MBbls) 1,559
 2,046
 (24)%
NGLs production (MBbls) 2,485
 2,615
 (5)%
Natural gas production (MMcf) 28,977
 33,064
 (12)%
Average oil price per barrel received $36.88
 $51.73
 (29)%
Average oil price per barrel received excluding derivatives $34.77
 $48.13
 (28)%
Average NGLs price per barrel received $8.90
 $10.37
 (14)%
Average NGLs price per barrel received excluding derivatives $8.90
 $10.37
 (14)%
Average natural gas price per Mcf received $1.83
 $2.80
 (35)%
Average natural gas price per Mcf received excluding derivatives $1.52
 $2.39
 (36)%
Contract Drilling:      
Average number of our drilling rigs in use during the period 17.1
 40.4
 (58)%
Total number of drilling rigs owned at the end of the period 94
 94
  %
Average dayrate $18,468
 $20,032
 (8)%
Mid-Stream:      
Gas gathered—Mcf/day 411,671
 348,666
 18 %
Gas processed—Mcf/day 164,333
 187,592
 (12)%
Gas liquids sold—gallons/day 525,824
 584,389
 (10)%
Number of natural gas gathering systems 26
 27
 (4)%
Number of processing plants 14
 13
 8 %
  June 30, 
%
Change
  2017 2016 
  (In thousands except percentages)
Working capital $(51,417) $(57,463) 11 %
Long-term debt less debt issuance costs $806,092
 $875,051
 (8)%
Shareholders’ equity $1,244,463
 $1,211,221
 3 %
Net income (loss) $24,988
 $(113,285) 122 %

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 $57.5$51.4 million and $11.4$57.5 million as of June 30, 20162017 and 2015,2016, respectively. This is primarily from the changean increase in value of remaining derivatives outstanding and lower accounts receivable due to lowerhigher revenues, the change in the value of outstanding derivatives, the reclassification of current deferred tax asset to long-term asset per ASU 2015-17, and decreased accrued liabilities partially offset by the timing ofincreased accounts payable associated with our capital expenditures.due to increased drilling activity and more rigs operating. Our credit agreement is used primarily for working capital and capital expenditures. At June 30, 2016,2017, we had borrowed $236.0$164.9 million of the $475.0 million available under our credit agreement. The effect of our derivative contracts increased working capital by $2.9 million as of June 30, 2017 and decreased working capital by $9.6 million as of June 30, 2016 and increased working capital by $14.6 million as of June 30, 2015.2016.


The following table summarizes certain operating information:
  Six Months Ended  
  June 30, 
%
Change
  2017 2016 
Oil and Natural Gas:      
Oil production (MBbls) 1,357
 1,559
 (13)%
NGLs production (MBbls) 2,233
 2,485
 (10)%
Natural gas production (MMcf) 24,232
 28,977
 (16)%
Average oil price per barrel received $47.77
 $36.88
 30 %
Average oil price per barrel received excluding derivatives $47.27
 $34.77
 36 %
Average NGLs price per barrel received $16.34
 $8.90
 84 %
Average NGLs price per barrel received excluding derivatives $16.34
 $8.90
 84 %
Average natural gas price per Mcf received $2.57
 $1.83
 40 %
Average natural gas price per Mcf received excluding derivatives $2.66
 $1.52
 75 %
Contract Drilling:      
Average number of our drilling rigs in use during the period 27.2
 17.1
 59 %
Total number of drilling rigs owned at the end of the period 95
 94
 1 %
Average dayrate $15,905
 $18,468
 (14)%
Mid-Stream:      
Gas gathered—Mcf/day 386,893
 411,671
 (6)%
Gas processed—Mcf/day 130,804
 164,333
 (20)%
Gas liquids sold—gallons/day 511,969
 525,824
 (3)%
Number of natural gas gathering systems 25
 26
 (4)%
Number of processing plants 13
 14
 (7)%

Oil and Natural Gas Operations

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

Based on our first six months of 20162017 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 $464,000$392,000 per month ($5.64.7 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 six months of 20162017 was $1.83$2.57 compared to $2.80$1.83 for the first six months of 2015.2016. Based on our first six months of 20162017 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $252,000$219,000 per month ($3.02.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of derivatives, would have a $399,000$362,000 per month ($4.84.3 million annualized) change in our pre-tax operating cash flow. In the first six months of 2016,2017, our average oil price per barrel received, including the effect of derivatives, was $36.88$47.77 compared with an average oil price, including the effect of derivatives, of $51.73$36.88 in the first six months

of 20152016 and our first six months of 20162017 average NGLs price per barrel received was $8.90$16.34 compared with an average NGLs price per barrel of $10.37$8.90 in the first six months of 2015.2016.

Because commodity prices affect the value of our oil, NGLs, and natural gas reserves, declines in those prices can cause a decline in the carrying value of our oil and natural gas properties. Price declines can also adversely affect the semi-annual determination of the amount available for us to borrow under our credit agreement since that determination is based mainly on the value of our oil, NGLs, and natural gas reserves. A reduction could limit our ability to carry out our planned capital projects. In the first quarter of 2016, the unamortized cost of our oil and gas properties exceeded the ceiling of our proved oil, NGLs, and natural gas reserves. As a result, we recorded a non-cash ceiling test write down of $37.8 million pre-tax ($23.5 million, net of tax). During the second quarter of 2016, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of $74.3 million pre-tax ($46.3 million, net of tax). At June 30, 2016,2017, the 12-month average unescalated prices were $43.12$48.95 per barrel of oil, $17.79$24.97 per barrel of NGLs, and $2.24$3.01 per Mcf of natural gas, thenas adjusted for price differentials. We did not have to take a write down in the first six months of 2017.

It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to

these factors and inherent limitations,uncertainties, if we hold these same factors constant as they existed on July 1, 2016at June 30, 2017, and only adjustedadjust the 12-month average price to an estimated secondthird quarter ending average (holding July 20162017 prices constant for the remaining two months of the third quarter of 2016)2017), our forward looking expectation is that we wouldwill not expect to recognize an impairment in the third quarter of 2016. Commodity2017. But commodity prices (and other factors) remain volatile and have recently trended downward and should that trend continue itthey could negatively impactaffect the 12-month average price andresulting in the potential for an impairment in the third quarter.

Given the uncertainty associated with the factors used in calculating our estimate of both our future period ceiling test write-down and the decrease in our undeveloped reserves, these estimates should not necessarily be construed as indicative of our future development plans or financial results.

Price declines can also adversely affect future semi-annual determinations of the amount we can borrow under our credit agreement since that determination is based mainly on the value of our oil, NGLs, and natural gas reserves. Such a reduction could limit our ability to carry out our planned capital projects. Under the third amendment to our credit agreement entered into on April 8, 2016, the lenders decreased our borrowing base from $550.0 million to $475.0 million. Our commitment under the credit agreement decreased from $500.0 million to $475.0 million.future.

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

Contract Drilling Operations

Many factors influence the number of drilling rigs we are working at any given time as well asand 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.

Our drilling rig personnel are a key component to the overall success of our drilling services; however, due to the present conditions existing in the drilling industry, we reduced the compensation paid to all drilling personnel in April 2016.

Almost allMost of our working drilling rigs arewere drilling horizontal or directional wells for oil and NGLs. The continued lowimproved commodity price environmentpricing for oil and natural gas that began during the second half of 2016 has changedincreased demand for drilling rigs. These factors ultimately affect the demand and mix of the type of drilling rigs used by our customerscustomers. The future demand for and the availability of drilling rigs to meet that demand will have an impact onaffect our future dayrates. For the first six months of 20162017, our average dayrate was $18,468$15,905 per day compared to $20,032$18,468 per day for the first six months of 2015.2016. The average number of our drilling rigs used in the first six months of 20162017 was 17.127.2 drilling rigs compared with 40.417.1 drilling rigs in the first six months of 2015.2016. Based on the average utilization of our drilling rigs during the first six months of 20162017, a $100 per day change in dayrates has a $1,710$2,720 per day ($0.61.0 million annualized) change in our pre-tax operating cash flow.

Our contract drilling segment also provides drilling services for our oilexploration and natural gasproduction 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 drilling services are eliminated in our

statement of operations, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We did not eliminate anyeliminated revenue in our contract drilling segmentof $5.6 million for the first six months of 2016 and the oil and gas segment did not use any of our rigs in the second quarter. Our oil and natural gas segment to incur the majority of its drilling capital expenditures in the latter part of the year thus allowing us to take into account future commodity price movement before those expenditures are incurred. For the first six months of 2015, we eliminated revenue of $15.7 million2017 from our contract drilling segment and eliminated the associated operating expense of $12.2$5.2 million yielding $3.5$0.4 million as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue in our contract drilling segment for the first six months of 2016.

Mid-Stream Operations

Our mid-stream segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates three natural gas treatment plants, 1413 processing plants, 2625 gathering systems, and approximately 1,4501,470 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 six months of 20162017 and 20152016, our mid-stream operations purchased $16.4$27.3 million and $33.0$16.4 million,, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $5.1$3.2 million and $3.8$5.1 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 386,893 Mcf per day in the first six months of 2017 compared to 411,671 Mcf per day in the first six months of 2016 compared to 348,666. It processed an average of 130,804 Mcf per day in the first six months of 2015. It processed an average of2017 compared to 164,333 Mcf per day in the first six months of 2016 compared to 187,592 Mcf2016. The amount of NGLs sold was 511,969 gallons per day in the first six months of 2015. The amount of NGLs sold was2017 compared to 525,824 gallons per day in the first six months of 2016 compared to 584,389 gallons per day in the first six months of 2015.2016. Gas gatheringgathered volumes per day in the first six months of 2016 increased 18%2017 decreased 6% compared to the first six months of 20152016 primarily from additionaldue to declines in existing volumes, fewer new wells added toconnected, and losing an offload volume at our Pittsburgh Mills gathering system. ProcessedHemphill facility in mid-2016. Gas processed volumes for the first six months of 20162017 decreased 12%20% from the first six months of 20152016 due to declines in existing volumes, fewer new wells connected to our processing systems, and losing an offload volume at our Hemphill facility in our systems where we process gas combined with few replacement wells due to decreased drilling activity by operators in those areas.mid-2016. NGLs sold decreased 10%3% from the comparative period due to less volume available to process at our plants.


At-the-Market (ATM) Common Stock Program

On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $0.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions we may impose).
We do not have to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
As of July 21, 2017, we sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million.

Our Credit Agreement and Senior Subordinated Notes

Credit Agreement. On April 8, 2016, we amended ourOur Senior Credit Agreement (credit agreement) is scheduled to mature on April 10, 2020. TheUnder the credit agreement, the amount we can borrow is the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed the maximum credit agreement amount of $875.0 million. Our elected commitment amount is $475.0 million. Our borrowing base is $475.0 million. We are charged a commitment fee of 0.50% on the amount available but not borrowed. TheThat fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. WithUnder the new amendment,credit agreement, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our midstream affiliate, Superior Pipeline Company, L.L.C.

The current lenders under our credit agreement and their respective participation interests are:
Lender 
Participation
Interest
BOK (BOKF, NA, dba Bank of Oklahoma) 17%
Compass Bank 17%
BMO Harris Financing, Inc. 15%
Bank of America, N.A. 15%
Comerica Bank 8%
Wells Fargo Bank, N.A. 8%
Canadian Imperial Bank of Commerce 8%
Toronto Dominion (New York), LLC 8%
The Bank of Nova Scotia 4%
  100%

The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the credit agreement.


At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At June 30, 20162017 and July 22, 2016,21, 2017, borrowings were $236.0$164.9 million and $238.6$172.1 million, respectively.

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

The credit agreement prohibits, among other things:

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

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

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

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

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

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

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

As of June 30, 2016,2017, we were in compliance with the covenants in the credit agreement.agreement covenants.

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 will 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 the issuance ofissuing the Notes. The Guarantors are most of our direct and indirect subsidiaries. The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.

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

On and after May 15, 2016, weWe may redeem all or, from time to time,occasionally, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants

including those that among other things, 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 June 30, 2016.2017.

Capital Requirements

Oil and Natural Gas Segment Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward future growth. Our decisions to increase our oil, NGLs, and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential, and opportunities to obtain financing under the circumstances involved, all of which provide us with flexibility in deciding when and if to incur these costs. We completed drilling 1319 gross wells (7.65(8.21 net wells) in the first six months of 20162017 compared to 3313 gross wells (21.85(7.65 net wells) in the first six months of 2015. 2016.

On April 3, 2017, we closed an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The preliminary adjusted value of consideration given was $54.0 million. As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition adds approximately 8,300 net oil and gas leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. This acquisition includes 13 potential horizontal drilling locations not otherwise included in our existing acreage. Of the acreage acquired, approximately 71% is held by production. We also received one gathering system as part of the transaction.

Capital expenditures for oil and gas properties on the full cost method for the first six months of 20162017 by this segment, excluding $54.0 million for acquisitions and a $2.0 million reduction in the ARO liability, totaled $84.5 million. Capital expenditures for the first six months of 2016, excluding a $28.9 million reduction in the ARO liability, totaled $76.2 million. Capital expenditures for the first six months of 2015, excluding a $6.0 million reduction in the ARO liability, totaled $167.6 million.

Currently weWe plan to participate in drilling approximately 2035 to 2540 gross wells in 20162017 and our total estimated capital expenditures (excluding any possible acquisitions) for this segment range fromare approximately $109.0 million to $131.0$197.0 million. 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 second quarter of 2015, we recorded a write-down of approximately $8.3 million pre-tax on drilling equipment that was being held for sale.

During the first quarter of 2015,2017, we had twowere awarded a term contract to build our tenth BOSS rig. Construction was completed and the drilling rigsrig was placed into service for third-party operators. The long lead time components for three additional BOSS drilling rigs were ordered in 2014 in anticipation for future demand of the BOSS drilling rigs. However, with the declinelate in the drilling market, many of these long lead time components were either postponed for later delivery or canceled altogether. Currently, we do not have any contracts to build new BOSS drilling rigs.second quarter.

Our estimated 20162017 capital expenditures for this segment range from $9.0 million to $11.0are approximately $28.0 million. At June 30, 2016,2017, we had commitments to purchase approximately $4.8$3.9 million for drilling equipment over the next two years.year. We have spent $22.7 million for capital expenditures during the first six months of 2017, compared to $5.2 million for capital expenditures during the first six months of 2016, compared to $70.1 million for capital expenditures, including $53.8 million for the BOSS drilling rigs, during the first six months of 2015.2016.

Mid-Stream Acquisitions and Capital Expenditures. In the Appalachian region, our Pittsburgh Mills gathering system, in Allegheny and Butler counties, continues to produce consistent financial results. Our average gathered volume for the second quarter of 2017 is approximately 133 MMcf per day. We connected the new Allen well pad in May and it included five new wells. And we are constructing a pipeline to connect the Miller well pad, which will be the next pad connected to our system. The Miller pad will include seven new wells and we anticipate it will be ready to flow in the third quarter of 2018. Also, we anticipate several in-fill wells to be drilled and connected to our system in the first half of 2018.

At our Hemphill Texas system, our total throughput volume averaged 57.5 MMcf per day for the second quarter of 2016, our total throughput volume averaged 69.3 MMcf per day2017 and our total production of natural gas liquids was approximately 172,200142,000 gallons per day. At this processing facility we have the capacity to process 135 MMcf per day through three processing skids. During the second quarter, we connected one new long lateral well to this system.

At our Bellmon processing facility located in the Mississippian play in north central Oklahoma, our total throughput volume averaged approximately 34 MMcf per day for the second quarter of 2016. Additionally, during the second quarter, we increased our natural gas liquids volume to approximately 130,800 gallons per day. After minor modifications to our gathering system, we have been receiving additional volumes from third party producers since the first of this year. During the first six months of 2016, we connected 15 additional wells to this gathering system. At this processing facility we have two processing skids available that provide totalTotal processing capacity of 90 MMcf per day.

At our Segno gatheringat this facility located Southeast Texas, our average transported volume increased to over 90 MMcf per day for the second quarter of 2016. Since the first of this year, we connected three new wells to this gathering system. With the completion of the GAP pipeline extension project, our total gathering capacity has increased to 120 MMcf per day for this system.

In the Appalachian region, at our Pittsburgh Mills gathering system, our average throughput volume continues to increase. During the second quarter of 2016 the total throughput volume increased to approximately 142.5 MMcf per day. Since the beginning of this year we have connected three new well pads with a total of 12 new wells to this gathering system. In June, we connected the Thompson well pad which included two new wells. The Thompson well pad is located on the northern end of our system and delivers gas into NiSource’s Big Pine system. We have completed construction of a pipeline to connect our next well pad which is the Belo pad. There are six wells located on this pad and it was connected and began flowing gas in July.

Also in the Appalachian area at our Snow Shoe gathering system, since the first of this year, we have connected three well pads that have a total of six wells. Our average throughput volume for the second quarter of 2016 has increased to approximately 14135 MMcf per day. During the second quarter, we connected one new well padand since the beginning of 2017, we connected two new wells to this processing facility. Our oil and gas segment continues to operate a rig and we anticipate connecting four more wells in the third quarter.  

At our Cashion processing facility in central Oklahoma, our total throughput volume for the second quarter of 2017 averaged approximately 37.8 MMcf per day and our total production of natural gas liquids increased to approximately 207,000 gallons per day. Total processing capacity for this facility remains at approximately 45 MMcf per day. In the first six months of 2017, we connected one new well and completed a construction project that had threeallows us to bring additional gas to this processing plant from a third party producer. This new producer will deliver fee-based volume to us for five years or will pay a shortfall

fee settled annually. And we are constructing a new pipeline extension which will allow us to connect a new producer to our system. Construction of this pipeline is underway and we expect to connect the first well to our system in the thrid quarter of this year. 

At our Bellmon processing facility in the Mississippian play in north central Oklahoma, we connected six new wells which began flowing in April.the second quarter of 2017 and our total throughput volume averaged approximately 27 MMcf per day. Total natural gas liquids averaged approximately 137,700 gallons per day while operating in ethane recovery mode at this facility. Total processing capacity at this system is approximately 90 MMcf per day.

At our Segno gathering facility in Southeast Texas, gathered volume for the second quarter of 2017 averaged approximately 79.2 MMcf per day. At this facility, we have increased our gathering and dehydration capacity to approximately 120 MMcf per day. We have completed preliminary construction of the Snow Shoe compressor station but we will not complete the compressor station until compression services are required.connected one new well to this system in 2017.

During the first six months of 2016,2017, our mid-stream segment incurred $8.5$5.4 million in capital expenditures as compared to $24.3$8.5 million in the first six months of 2015.2016. For 2016,2017, our estimated capital expenditures range from $22.0 million to $24.0are approximately $16.0 million.

Contractual Commitments

At June 30, 2016,2017, we had certain contractual obligations including:
 Payments Due by Period Payments Due by Period
 Total 
Less
Than
1 Year
 
2-3
Years
 
4-5
Years
 
After
5 Years
 Total 
Less
Than
1 Year
 
2-3
Years
 
4-5
Years
 
After
5 Years
 (In thousands) (In thousands)
Long-term debt (1)
 $1,130,532
 $52,231
 $104,463
 $973,838
 $
 $997,789
 $48,802
 $261,234
 $687,753
 $
Operating leases (2)
 4,411
 3,095
 1,172
 144
 
 5,470
 3,549
 1,551
 370
 
Capital lease interest and maintenance(3)
 10,815
 2,548
 4,647
 3,603
 17
 8,267
 2,400
 4,334
 1,533
 
Drill pipe, drilling components, and equipment purchases (4)
 4,762
 2,819
 1,943
 
 
 3,887
 3,887
 
 
 
Enterprise Resource Planning software obligations (5)
 1,436
 950
 486
 
 
Total contractual obligations $1,151,956
 $61,643
 $112,711
 $977,585
 $17
 $1,015,413
 $58,638
 $267,119
 $689,656
 $
_______________________ 
(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, 20162017 interest rates of 6.625% for the Notes and 3.9%3.5% for the credit agreement. Our credit agreement has a maturity date of April 10, 2020.

(2)We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Pittsburgh,Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.

(3)Maintenance and interest payments are included in our capital lease agreements. The capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining are $8.5$6.8 million and $2.3$1.5 million, respectively.

(4)We have committed to pay $4.8$3.9 million for drilling rig components, drill pipe, and related equipment over the next two years.

(5)We have committed to pay $0.9 million for Enterprise Resource Planning software and $0.5 million for maintenance for one year following implementation.year.



At June 30, 2016,2017, we also had the following commitments and contingencies that could create, increase, or accelerate our liabilities:
 Estimated Amount of Commitment Expiration Per Period Estimated Amount of Commitment Expiration Per Period
Other Commitments 
Total
Accrued
 
Less
Than 1
Year
 
2-3
Years
 
4-5
Years
 
After 5
Years
 
Total
Accrued
 
Less
Than 1
Year
 
2-3
Years
 
4-5
Years
 
After 5
Years
 (In thousands) (In thousands)
Deferred compensation plan (1)
 $4,430
 Unknown
 Unknown
 Unknown
 Unknown
 $5,092
 Unknown
 Unknown
 Unknown
 Unknown
Separation benefit plans (2)
 $6,386
 $3,897
 Unknown
 Unknown
 Unknown
 $5,456
 $830
 Unknown
 Unknown
��Unknown
Asset retirement liability (3)
 $70,926
 $3,523
 $43,062
 $6,301
 $18,040
 $70,049
 $2,825
 $44,157
 $5,855
 $17,212
Gas balancing liability (4)
 $3,805
 Unknown
 Unknown
 Unknown
 Unknown
 $3,322
 Unknown
 Unknown
 Unknown
 Unknown
Repurchase obligations (5)
 $
 Unknown
 Unknown
 Unknown
 Unknown
 $
 Unknown
 Unknown
 Unknown
 Unknown
Workers’ compensation liability (6)
 $15,258
 $6,959
 $3,319
 $1,264
 $3,716
 $13,971
 $7,170
 $1,728
 $965
 $4,108
Capital leases obligations (7)
 $20,710
 $3,620
 $7,690
 $9,238
 $162
 $17,089
 $3,768
 $8,003
 $5,318
 $
Other $410
 Unknown
 $410
 Unknown
 Unknown
 $410
 Unknown
 $410
 Unknown
 Unknown
_______________________ 
(1)We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death, or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets, at the time of deferral.

(2)Effective January 1, 1997, we adopted a separation benefit plan (“Separation Plan”). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Currently there are no participants in the Senior Plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (“Special Plan”). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. On December 31, 2008, all these plans were amended to bring the plans into compliance with Section 409A of the Internal Revenue Code of 1986, as amended.

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

(4)We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners to recover their under-production from future production volumes.

(5)We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the “Partnerships”) with certain qualified employees, officers and directors from 1984 through 2011. One of our subsidiaries serves as the general partner of each of these programs. Effective December 31, 2014, The Unit 1984 Oil and Gas Limited Partnership dissolved and effective December 31, 2016, the two 1986 partnerships were dissolved. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. Repurchases in any one year are limited to 20% of the units outstanding. We madedid not have any repurchases of $8,000 during the first six months of 2015 but did not have any for the first six months of2017 or 2016.

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

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

Derivative Activities

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








Commodity Derivatives. Our commodity derivatives are intended to reduce our exposure to price volatility and manage price risks. Our decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our view of current and future market conditions. At June 30, 2016,2017, based on our second quarter 20162017 average daily production, the approximated percentages of our production under derivative contracts are as follows:
 Q3 Q4     Q2 Q3 Q4 Q1 Q2 Q3 Q4
 2016 2016 2017 2018 2017 2018
Daily oil production 58% 34% 9% % 48% 48% 48% 13% 13% 13% 13%
Daily natural gas production 63% 63% 52% 6% 80% 80% 70% 61% 30% 30% 30%

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 June 30, 20162017 evaluation, we believe the risk of non-performance by our counterparties is not material. At June 30, 2016,2017, the fair values of the net liabilitiesassets (liabilities) we had with each of the counterparties to our commodity derivative transactions are as follows:
 June 30, 2016 June 30, 2017
 (In millions) (In millions)
Bank of Montreal $(6.2) $4.6
Canadian Imperial Bank of Commerce (3.4) (0.6)
Bank of America Merrill Lynch (1.8)
Scotiabank (1.7) (0.4)
Total liabilities $(13.1)
Total assets $3.6

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 June 30, 2016, we recorded the fair value of our commodity derivatives on our balance sheet as current and non-current derivative liabilities of $9.7 million and $3.4 million, respectively. At June 30, 2015,2017, we recorded the fair value of our commodity derivatives on our balance sheet as current and non-current derivative assets of $14.6$3.9 million and $0.1$0.7 million, respectively, and current derivative liabilities of $1.0 million. At December 31, 2016, we recorded the fair value of our commodity derivatives on our balance sheet as non-current derivative assets of $0.4 million, and current and non-current derivative liabilities of $21.6 million and $0.4 million, respectively.

For our economic hedges any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations. These gains (losses) at June 30 are as follows:
 Three Months Ended Six Months Ended Three Months Ended Six Months Ended
 June 30, June 30, June 30, June 30,
 2016 2015 2016 2015 2017 2016 2017 2016
 (In thousands) (In thousands)
Gain (loss) on derivatives:                
Gain (loss) on derivatives, included are amounts settled during the period of $5,052, $10,070, $12,192, and $21,082, respectively $(22,672) $(1,919) $(11,743) $4,667
Gain (loss) on derivatives, included are amounts settled during the period of ($410), $5,052, ($1,569) and $12,192, respectively $8,902
 $(22,672) $23,633
 $(11,743)
 $(22,672) $(1,919) $(11,743) $4,667
 $8,902
 $(22,672) $23,633
 $(11,743)


Stock and Incentive Compensation

During the first six months of 20162017, 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 six months of 2017, we recognized $2.9 million in compensation expense and capitalized $0.5 million for these awards. During the first six months of 2017, we recognized compensation expense of $5.8 million for all of our restricted stock, stock options, and SAR grants and capitalized $0.8 million of compensation cost for oil and natural gas properties.

During the first six months of 2016, we granted awards covering 728,951 shares of restricted stock. These awards had an estimated fair value as of their grant date of $4.2$4.3 million. Compensation expense will be recognized over the three year vesting periods, and during the six months of 2016, we recognized $0.6 million in compensation expense and capitalized less than $0.1 million for these awards. During the first six months of 2016, we recognized compensation expense of $5.3 million for all of our restricted stock, stock options, and SAR grants and capitalized $1.2 million of compensation cost for oil and natural gas properties.

During the first six months of 2015 we granted awards covering 750,290 shares of restricted stock. These awards had an estimated fair value as of their grant date of $24.5 million. Compensation expense will be recognized over the three year vesting periods, and during the six months of 2015, we recognized $3.6 million in compensation expense and capitalized $0.8 million for these awards. During the first six months of 2015, we recognized compensation expense of $9.1 million for all of our restricted stock, stock options, and SAR grants and capitalized $1.9 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 1513 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 each of the first six months of 20162017 and 2015,2016, the total we received for all of these fees was less than $0.1 million and $0.2 million.million, respectively. Our proportionate share of assets, liabilities, and net income (loss) relating to the oil and natural gas partnerships is included in our unaudited condensed consolidated financial statements.

New Accounting Pronouncements

Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting.Compensation. The FASB has issued ASU 2016-09.2017-09, to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms and conditions of a share-based payment award. The amendments are effective for reporting periods beginning after December 15, 2017. We are in the process of evaluating the impact these amendments will have on our financial statements.

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

Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to improve the accountinghelp companies and other organizations evaluate whether transactions should be accounted for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspectsas acquisitions (or disposals) of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equityassets or liabilities; and (c) classification on the statement of cash flows.businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2016,2017. We are in the process of evaluating the impact these amendments will have on our financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and interim periods within those annual periods. Early adoption of the amendments is permitted. Cash Payments.  The amendments primarily impact classification withinFASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows between financialflows. The amendments

will be effective retrospectively for reporting periods beginning after December 31, 2017, and operating activities.early adoption is permitted. We do not believe thethese amendments will have a material impact on our financial statements.

Leases. The FASB has issued ASU 2016-02. Under the new guidance,The amendments will require lessees will be required to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendments are effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. Early adoption of the amendments inis permitted. We are in the process of evaluating the impact itthese amendments will have on our financial statements.

Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations will be required to classify all deferred tax assets

and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. The amendments will require current deferred tax assets to be combined with noncurrent deferred tax assets. We do not believe the amendments will have a material impact on our financial statements.

Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The FASB has issued ASU 2015-03. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The FASB has also issued ASU 2015-15. The amendments in this ASU allow an entity to defer and present debt issuance cost as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We have maintained debt issuance costs associated with our credit agreement as an asset and amortize these fees over the life of the credit agreement. For public business entities, the amendments are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. We have adopted these amendments during the first quarter of 2016. Previously, debt issuance costs associated with the Notes was classified as a long-term asset on the balance sheet, but with ASU 2015-03, it is presented as a direct deduction from the carrying amount of the recognized debt liability.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This affectsThese amendments affect any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the guidanceamendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-12, "Narrow-Scope Improvements and Practical Expedients," which provides clarifying guidance in certain areas and adds some practical expedients. Also in May 2016, the FASB issued ASU 2016-11, "Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting." This ASUamendment rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities—Activities- Oil and Gas, effective uponon the adoption of Topic 606, Revenue from Contracts with Customers. In April 2016, the FASB issued ASU 2016-10, "Identifying Performance Obligations and Licensing," which amends the revenue guidance on identifying performance obligations and accounting for licenses of intellectual property. The FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We will adopt these amendments effective January 1, 2018. We are utilizing a bottom-up approach to analyze the impact of the new standard on our contracts by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard. We have an implementation team evaluating contracts for the various revenue streams of our business segments to address changes to business processes, systems, and controls. While we have not identified any material differences in the processamount and timing of evaluatingrevenue recognition to date, our evaluation is not complete, and we have not reached a conclusion on the overall impacts of adopting Topic 606. Topic 606 provides for adoption either retrospectively to each prior reporting period presented or as a cumulative effect adjustment to retained earnings at the date of adoption. We plan to adopt using the cumulative effect method.

Adopted Standards

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

Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments primarily impact it willclassification within the statement of cash flows between financial and operating activities. This did not have a material impact on our financial statements.


Results of Operations
Quarter Ended June 30, 20162017 versus Quarter Ended June 30, 20152016
Provided below is a comparison of selected operating and financial data:
  Quarter Ended June 30, 
Percent
Change (1)
  2017 2016 
  (In thousands unless otherwise specified)  
Total revenue $170,581
 $138,305
 23 %
Net income (loss) $9,059
 $(72,136) 113 %
       
Oil and Natural Gas:      
Revenue $83,173
 $69,190
 20 %
Operating costs excluding depreciation, depletion, amortization, and impairment $32,758
 $33,331
 (2)%
Depreciation, depletion, and amortization $23,558
 $30,411
 (23)%
Impairment of oil and natural gas properties $
 $74,291
 (100)%
       
Average oil price received (Bbl) $46.96
 $41.52
 13 %
Average NGLs price received (Bbl) $14.91
 $11.38
 31 %
Average natural gas price received (Mcf) $2.45
 $1.80
 36 %
Oil production (Bbl) 714,000
 756,000
 (6)%
NGLs production (Bbl) 1,136,000
 1,194,000
 (5)%
Natural gas production (Mcf) 12,007,000
 14,455,000
 (17)%
Depreciation, depletion, and amortization rate (Boe) $5.76
 $6.60
 (13)%
       
Contract Drilling:      
Revenue $39,255
 $24,257
 62 %
Operating costs excluding depreciation $27,239
 $19,254
 41 %
Depreciation $13,769
 $10,918
 26 %
       
Percentage of revenue from daywork contracts 100% 100%  %
Average number of drilling rigs in use 28.8
 13.5
 113 %
Average dayrate on daywork contracts $15,962
 $18,585
 (14)%
       
Mid-Stream:      
Revenue $48,153
 $44,858
 7 %
Operating costs excluding depreciation and amortization $36,042
 $32,381
 11 %
Depreciation and amortization $10,849
 $11,515
 (6)%
       
Gas gathered—Mcf/day 383,440
 439,937
 (13)%
Gas processed—Mcf/day 135,002
 161,619
 (16)%
Gas liquids sold—gallons/day 525,920
 532,215
 (1)%
       
Corporate and other:      
General and administrative expense $8,713
 $8,348
 4 %
Other depreciation $1,904
 $34
 NM
Gain on disposition of assets $248
 $477
 (48)%
Other income (expense):      
Interest expense, net $(9,467) $(10,606) (11)%
Gain (loss) on derivatives $8,902
 $(22,672) 139 %
Other $6
 $1
 NM
Income tax expense (benefit) $6,379
 $(42,842) 115 %
Average long-term debt outstanding $816,649
 $908,493
 (10)%
Average interest rate 6.0% 5.6% 7 %
  Quarter Ended June 30, 
Percent
Change (1)
  2016 2015 
  (In thousands unless otherwise specified)  
Total revenue $138,305
 $214,447
 (36)%
Net loss $(72,136) $(274,389) (74)%
       
Oil and Natural Gas:      
Revenue $69,190
 $107,256
 (35)%
Operating costs excluding depreciation, depletion, amortization, and impairment $33,331
 $45,972
 (27)%
Depreciation, depletion, and amortization $30,411
 $68,101
 (55)%
Impairment of oil and natural gas properties $74,291
 $410,536
 (82)%
       
Average oil price received (Bbl) $41.52
 $55.52
 (25)%
Average NGLs price received (Bbl) $11.38
 $12.05
 (6)%
Average natural gas price received (Mcf) $1.80
 $2.67
 (33)%
Oil production (Bbl) 756,000
 948,000
 (20)%
NGLs production (Bbl) 1,194,000
 1,328,000
 (10)%
Natural gas production (Mcf) 14,455,000
 16,665,000
 (13)%
Depreciation, depletion, and amortization rate (Boe) $6.60
 $13.14
 (50)%
       
Contract Drilling:      
Revenue $24,257
 $55,015
 (56)%
Operating costs excluding depreciation $19,254
 $36,485
 (47)%
Depreciation $10,918
 $13,265
 (18)%
Impairment of contract drilling equipment $
 $8,314
 (100)%
       
Percentage of revenue from daywork contracts 100% 100%  %
Average number of drilling rigs in use 13.5
 30.7
 (56)%
Average dayrate on daywork contracts $18,585
 $19,881
 (7)%
       
Mid-Stream:      
Revenue $44,858
 $52,176
 (14)%
Operating costs excluding depreciation and amortization $32,381
 $40,592
 (20)%
Depreciation and amortization $11,515
 $10,848
 6 %
       
Gas gathered—Mcf/day 439,937
 362,896
 21 %
Gas processed—Mcf/day 161,619
 186,041
 (13)%
Gas liquids sold—gallons/day 532,215
 599,732
 (11)%
       
Corporate and other:      
General and administrative expense $8,382
 $9,624
 (13)%
Gain on disposition of assets $477
 $415
 15 %
Other income (expense):      
Interest expense, net $(10,606) $(7,956) 33 %
Loss on derivatives $(22,672) $(1,919) NM
Other $1
 $24
 (96)%
Income tax benefit $(42,842) $(164,337) (74)%
Average long-term debt outstanding $908,493
 $906,609
  %
Average interest rate 5.6% 5.4% 4 %
________________________________________________
(1)NM - A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.


Oil and Natural Gas

Oil and natural gas revenues decreased $38.1increased $14.0 million or 35%20% in the second quarter of 20162017 as compared to the second quarter of 20152016 primarily due to lower oil, NGLs, and natural gashigher commodity prices and to a lesser extentpartially offset from reduced production volumes. In the second quarter of 2016,2017, as compared to the second quarter of 2015,2016, oil production decreased 20%6%, natural gas production decreased 13%17%, and NGLs production decreased 10%5%. Average oil prices decreased 25%increased 13% to $41.52$46.96 per barrel, average natural gas prices decreased 33%increased 36% to $1.80$2.45 per Mcf, and NGLs prices decreased 6%increased 31% to $11.38$14.91 per barrel.

Oil and natural gas operating costs decreased $12.6$0.6 million or 27%2% between the comparative second quarters of 20162017 and 20152016 due to lower LOE and saltwater disposal expense, andexpenses partially offset by higher general and administrative expenses.

Depreciation, depletion, and amortization (“DD&A”) decreased $37.7$6.9 million or 55%23% due primarily to a 50%13% decrease in our DD&A rate and a 14%12% decrease in equivalent production. The decrease in our DD&A rate in the second quarter of 20162017 compared to the second quarter of 20152016 resulted primarily from the effect of the ceiling test write-downs throughout 2015. Our DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities adjusted for current period production.2016.

During the second quarter of 2015, we recorded a non-cash ceiling test write-down of $410.5 million pre-tax ($255.6 million, net of tax). During the second quarter of 2016, we recorded a non-cash ceiling test write-down of $74.3 million pre-tax ($46.3 million, net of tax). We did not have a write-down for the second quarter of 2017.

Contract Drilling

Drilling revenues decreased $30.8increased $15.0 million or 56%62% in the second quarter of 20162017 versus the second quarter of 2015.2016. The decreaseincrease was due primarily to a 56% decrease113% increase in the average number of drilling rigs in use as well aspartially offset by a 7%14% decrease in the average dayrate. Average drilling rig utilization decreasedincreased from 30.7 drilling rigs in the second quarter of 2015 to 13.5 drilling rigs in the second quarter of 2016. Revenue on contracts that terminated2016 to 28.8 drilling rigs in the second quarter of 2017. We recorded $0.8 million in early weretermination revenue in the second quarter of 2017 compared to $0.4 million in the second quarter of 2016 compared to $1.6 million in the second quarter of 2015.2016.

Drilling operating costs decreased $17.2increased $8.0 million or 47%41% between the comparative second quarters of 20162017 and 2015.2016. The decreaseincrease was due primarily to fewermore drilling rigs operating.operating partially offset by decreases in per day cost. Contract drilling depreciation decreased $2.3increased $2.9 million or 18%26% also due primarily to fewermore drilling rigs operating. During the second quarter of 2015, we recorded a write-down of approximately $8.3 million pre-tax on drilling equipment that was being held for sale.

Mid-Stream

Our mid-stream revenues decreased $7.3increased $3.3 million or 14%7% in the second quarter of 20162017 as compared to the second quarter of 20152016 due primarily from the average price for naturalto increases in gas, NGLs, and condensate sold decreasing 28%prices. Gas processed volumes per day decreased 16% between the comparative quarters primarily due to declines in existing volumes, fewer new wells connected to our processing systems, and 24%, respectively and from gas sales and liquids volumes decreasing 15% and 11%, respectively, offset partially bythe loss of an increaseoffload volume at our Hemphill facility in transportation volumes and prices of 60% and 13%, respectively.mid-2016. Gas processinggathered volumes per day decreased 13% between the comparative quarters primarily due to declines in existing volumes. Gas gathering volumes, per day increased 21% between the comparative quarters primarily due to additionalfewer new wells addedconnected to our Pittsburgh Mills gathering system.systems, and the loss of an offload volume at our Hemphill facility in mid-2016.

Operating costs decreased $8.2increased $3.7 million or 20%11% in the second quarter of 20162017 compared to the second quarter of 20152016 primarily due to increases in gas, NGLs, and condensate prices partially offset by a 18% decrease in prices paid for natural gas purchased and an 14% decrease in purchaseprocessed volumes along with an 6%a decrease in field direct expenses and a 22% decrease in general and administrativeoperating expenses. Depreciation and amortization increaseddecreased $0.7 million, or 6%, primarily due to capital expenditures for upgradescertain assets being fully depreciated in 2017.

Other Depreciation

During the second quarter of 2017, we had $1.9 million of other depreciation primarily due to our new ERP accounting and reporting system that was implemented during the first quarter of 2017 as well connects.as depreciation on our corporate building.

General and Administrative

Corporate general and administrative expenses decreased $1.2increased $0.4 million or 13%4% in the second quarter of 20162017 compared to the second quarter of 20152016 primarily due to loweran increase in employee costs and a reduction to our workforce during the first quarter of 2016.costs.

Gain on Disposition of Assets

There was a $0.5$0.2 million gain on disposition of assets in the second quarter of 2017 primarily due to the sale of vehicles compared to a gain of $0.5 million for the disposition of assets in the second quarter of 2016 primarily due to the sale of two top drives and power units, several large trucks, trailers, forklifts, and smaller vehicles, compared to a gain of $0.4 million for the disposition of assets in the second quarter of 2015 primarily due to the sale of one gathering system in our mid-stream segment.vehicles.

Other Income (Expense)

Interest expense, net of capitalized interest, increased $2.7decreased $1.1 million between the comparative second quartersquarters of 20162017 and 20152016 due primarily to decreased capitalized interesta 10% decrease in average long-term debt outstanding in the second quarter of 2016 and to a lesser extent to the higher average bank debt outstanding and a higher average interest rate.2017. 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 second quarter of 20162017 was $3.6$4.0 million compared to $5.5$3.6 million in the second quarter of 2015,2016, and was netted against our gross interest of $14.2$13.5 million and $13.4$14.2 million for the second quarters of 20162017 and 2015,2016, respectively. Our average interest rate increased from 5.4% in the second quarter of 2015 to 5.6% in the second quarter of 2016 to 6.0% in the second quarter of 2017 and our average debt outstanding was $1.9$91.8 million higherlower in the second quarter of 20162017 as compared to the second quarter of 20152016 primarily due to the increasedecrease in outstanding borrowings under our credit agreement over the comparative periods.

LossGain (loss) on derivatives increased $20.8$31.6 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Income Tax BenefitExpense (Benefit)

Income tax benefit decreased $121.5expense increased $49.2 million between the comparative second quarters of 20162017 and 20152016 primarily due to decreasedincreased pre-tax loss primarily from a lower non-cash ceiling test write-down in the second quarter of 2016 versus the second quarter of 2015.income. Our effective tax rate was 37.3%41.3% for the second quarter of 20162017 compared to 37.5%37.3% for the first quarter of 2015.2016. The rate change was primarily due to increased deferred income tax expense related to non-qualified stock options that expired and were forfeited during the second quarter of 2017. There was no current income tax expense or benefit in the secondfirst quarter of 2016 compared to $0.8 million for the second quarter of 2015.2017 or 2016. We did not pay any income taxes in the second quarter of 2016.2017.


Six Months Ended June 30, 20162017 versus Six Months Ended June 30, 20152016
Provided below is a comparison of selected operating and financial data:
 Six Months Ended June 30, 
Percent
Change (1)
 Six Months Ended June 30, 
Percent
Change
 2016 2015  2017 2016 
 (In thousands unless otherwise specified)   (In thousands unless otherwise specified)  
Total revenue $274,489
 $469,546
 (42)% $346,305
 $274,489
 26 %
Net loss $(113,285) $(522,743) (78)%
Net income (loss) $24,988
 $(113,285) (122)%
            
Oil and Natural Gas:            
Revenue $127,464
 $213,325
 (40)% $170,771
 $127,464
 34 %
Operating costs excluding depreciation, depletion, amortization, and impairment $66,677
 $91,183
 (27)% $61,962
 $66,677
 (7)%
Depreciation, depletion, and amortization $62,243
 $145,219
 (57)% $45,084
 $62,243
 (28)%
Impairment of oil and natural gas properties $112,120
 $811,129
 (86)% $
 $112,120
 (100)%
            
Average oil price received (Bbl) $36.88
 $51.73
 (29)% $47.77
 $36.88
 30 %
Average NGLs price received (Bbl) $8.90
 $10.37
 (14)% $16.34
 $8.90
 84 %
Average natural gas price received (Mcf) $1.83
 $2.80
 (35)% $2.57
 $1.83
 40 %
Oil production (Bbl) 1,559,000
 2,046,000
 (24)% 1,357,000
 1,559,000
 (13)%
NGLs production (Bbl) 2,485,000
 2,615,000
 (5)% 2,233,000
 2,485,000
 (10)%
Natural gas production (Mcf) 28,977,000
 33,064,000
 (12)% 24,232,000
 28,977,000
 (16)%
Depreciation, depletion, and amortization rate (Boe) $6.66
 $13.98
 (52)% $5.58
 $6.66
 (16)%
            
Contract Drilling:            
Revenue $62,967
 $150,092
 (58)% $76,440
 $62,967
 21 %
Operating costs excluding depreciation $47,352
 $88,231
 (46)% $56,466
 $47,352
 19 %
Depreciation $23,113
 $28,278
 (18)% $26,616
 $23,113
 15 %
Impairment of contract drilling equipment $
 $8,314
 (100)%
            
Percentage of revenue from daywork contracts 100% 100%  % 100% 100%  %
Average number of drilling rigs in use 17.1
 40.4
 (58)% 27.2
 17.1
 59 %
Average dayrate on daywork contracts $18,468
 $20,032
 (8)% $15,905
 $18,468
 (14)%
            
Mid-Stream:            
Revenue $84,058
 $106,129
 (21)% $99,094
 $84,058
 18 %
Operating costs excluding depreciation and amortization $63,447
 $84,767
 (25)% $73,746
 $63,447
 16 %
Depreciation and amortization $22,974
 $21,542
 7 % $21,667
 $22,974
 (6)%
            
Gas gathered—Mcf/day 411,671
 348,666
 18 % 386,893
 411,671
 (6)%
Gas processed—Mcf/day 164,333
 187,592
 (12)% 130,804
 164,333
 (20)%
Gas liquids sold—gallons/day 525,824
 584,389
 (10)% 511,969
 525,824
 (3)%
            
Corporate and other:            
General and administrative expense $17,097
 $18,994
 (10)% $17,667
 $16,959
 4 %
Other depreciation $3,645
 $138
 NM
Gain on disposition of assets $669
 $960
 (30)% $1,072
 $669
 60 %
Other income (expense):            
Interest expense, net $(20,223) $(15,196) 33 % $(18,863) $(20,223) (7)%
Gain (loss) on derivatives $(11,743) $4,667
 NM
 $23,633
 $(11,743) NM
Other $(14) $22
 (164)% $9
 $(14) 164 %
Income tax benefit $(58,560) $(314,915) (81)%
Income tax expense (benefit) $20,315
 $(58,560) 135 %
Average long-term debt outstanding $890,459
 $876,510
 2 % $814,485
 $890,459
 (9)%
Average interest rate 5.6% 5.5% 2 % 6.0% 5.6% 7 %
_______________________
(1)NM - A percentage calculation is not meaningful due to a zero-value denominator or a percentage greater than 200.

Oil and Natural Gas

Oil and natural gas revenues decreased $85.9increased $43.3 million or 40%34% in the first six months 20162017 as compared to the first six months of 20152016 primarily due to lower oil, NGLs, and natural gashigher commodity prices and to a lesser extent from reducedpartially offset by lower production volumes. In the first six months of 2016,2017, as compared to the first six months of 2015,2016, oil production decreased 24%13%, natural gas production decreased 12%16%, and NGLs production decreased 5%10%. Average oil prices decreased 29%increased 30% to $36.88$47.77 per barrel, average natural gas prices decreased 35%increased 40% to $1.83$2.57 per Mcf, and NGLs prices decreased 14%increased 84% to $8.90$16.34 per barrel.

Oil and natural gas operating costs decreased $24.5$4.7 million or 27%7% between the comparative first six months of 20162017 and 20152016 due to lower LOE, saltwater disposal expense, gross production taxes, and general and administrative expenses offset partially by higher gross production taxes due to fewer credits.expenses.

DD&A decreased $83.0$17.2 million or 57%28% due primarily to a 52%16% decrease in our DD&A rate and a 13%14% decrease in equivalent production. The decrease in our DD&A rate in the first six months of 20162017 compared to the first six months of 20152016 resulted primarily from the effect of the ceiling test write-downs throughout 2015. Our DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities adjusted for current period production.2016.

During the first six months of 2015, we recorded a non-cash ceiling test write-down of $811.1 million pre-tax ($505.0 million, net of tax). During the first six months of 2016, we recorded a non-cash ceiling test write-downwrite-downs of $112.1 million pre-tax ($69.8 million, net of tax). We did not have a write-down for 2017.

Contract Drilling

Drilling revenues decreased $87.1increased $13.5 million or 58%21% in the first six months of 20162017 versus the first six months of 2015.2016. The decreaseincrease was due primarily to a 58% decrease59% increase in the average number of drilling rigs in use as well as an 8%partially offset by a 14% decrease in the average dayrate. Average drilling rig utilization decreasedincreased from 40.4 drilling rigs in the first six months of 2015 to 17.1 drilling rigs in the first six months of 2016. Revenue on contracts that terminated2016 to 27.2 drilling rigs in the first six months of 2017. We recorded $0.8 million in early weretermination revenue in the first six months of 2017 compared to $3.1 million in the first six months of 2016 compared to $14.3 million in the first six months of 2015.2016.

Drilling operating costs decreased $40.9increased $9.1 million or 46%19% between the comparative first six months of 20162017 and 2015.2016. The decreaseincrease was due primarily to fewermore drilling rigs operating.operating partially offset by decreased per day cost. Contract drilling depreciation decreased $5.2increased $3.5 million or 18%15% also due primarily to fewermore drilling rigs operating. During the first six months of 2015, we recorded a write-down of approximately $8.3 million pre-tax on drilling equipment that was being held for sale.

Mid-Stream

Our mid-stream revenues decreased $22.1increased $15.0 million or 21%18% in the first six months of 20162017 as compared to the first six months of 20152016 due primarily from the average price for naturalto increased gas, liquids,NGLs, and condensate sold decreasing 30%, 15%, and 31%, respectively and fromprices partially offset by a decreas in gas sales, liquids, and condensate volumes decreasing 13%, 10%, and 2%, respectively, offset partially by an increase in transportation volumes and prices of 58% and 5%, respectively.processed volumes. Gas processingprocessed volumes per day decreased 12%20% between the comparative periods primarily due to declines in existing volumes.volumes, fewer new wells connected, and the loss of an offload volume at our Hemphill facility in mid-2016. Gas gatheringgathered volumes per day increased 18%decreased 6% between the comparative periods primarily due to additionaldeclines in existing volumes, fewer new wells added toconnected, and the loss of an offload volume at our Pittsburgh Mills gathering system.Hemphill facility in mid-2016

Operating costs decreased $21.3increased $10.3 million or 25%16% in the first six months of 20162017 compared to the first six months of 20152016 primarily due to increases in gas, NGLs, and condensate prices partially offset by a 28% decrease in prices paid for natural gas purchasedprocessed volumes and an 13% decrease in purchase volumes along with an 7%a decrease in field direct expenses and an 11% decrease in general and administrative expense.operating expenses. Depreciation and amortization increased $1.4decreased $1.3 million, or 7%6%, primarily due to capital expenditures for upgradescertain assets being fully depreciated in 2017.

Other Depreciation

During the first six months of 2017, we had $3.6 million of other depreciation primarily due to our new ERP accounting and reporting system that was implemented during the first quarter of 2017 as well connects.as depreciation on our corporate building.

General and Administrative

Corporate general and administrative expenses decreased $1.9increased $0.7 million or 10%4% in the first six months of 20162017 compared to the first six months of 20152016 primarily due to lowerhigher employee costs and a reduction to our workforce during the first quarter of 2016.costs.

Gain on Disposition of Assets

There was an $1.1 million gain on disposition of assets in the first six months of 2017 primarily due to the sale of a corporate aircraft and vehicles, compared to a gain of $0.7 million gain onfor the disposition of assets in the first six months of 2016 primarily due to the sale of various rig components (including three top drives and power units), vehicles, and a drilling yard, compared to a gain of $1.0 million

for the disposition of assets in the first six months of 2015 primarily due to the sale of one gathering system, various rig components, vehicles, and to a lesser extent the sale of one drilling rig.yard.

Other Income (Expense)

Interest expense, net of capitalized interest, increased $5.0decreased $1.4 million between the comparative first six months of 20162017 and 20152016 due primarily to decreased capitalized interesta 9% decrease in the first six months of 2016 and to a lesser extent to the higher average banklong-term debt outstanding and a higher average interest rate.outstanding. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for the first six months of 20162017 was $7.6$7.8 million compared to $11.4$7.6 million in the first six months of 2015,2016, and was netted against our gross interest of $27.8$26.7 million and $26.6$27.8 million for the first six months of 20162017 and 2015,2016, respectively. Our average interest rate increased from 5.5%5.6% to 5.6%6.0% and our average debt outstanding was $13.9$76.0 million higherlower in the first six months of 20162017 as compared to the first six months of 20152016 primarily due to the increasedecrease in outstanding borrowings under our credit agreement over the comparative periods.

Gain (loss) on derivatives decreased $16.4increased $35.4 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Income Tax Expense (Benefit)

Income tax benefit decreased $256.4expense increased $78.9 million between the comparative first six months of 20162017 and 20152016 primarily due to decreasedincreased pre-tax lossincome. Our effective tax rate was 44.8% for the first six months of 2017 compared to 34.1% for the first six months of 2016. The increase was primarily from lower non-cash ceiling test write-downsdue to increased deferred tax expense related to our restricted stock vestings in both comparative periods whereby the increase in the first six months of 2017 increased our deferred income tax expense and the increase in the first six months of 2016 versus the first six months of 2015. Our effectivedecreased our income tax rate was 34.1% for the first six months of 2016 compared to 37.6% for the first six months of 2015. This decrease is primarily due to increased deferred tax expense in the first six months of 2016 related to our restricted stock vestings in the first six months of 2016 after the exhaustion of our remaining accumulated excess tax benefits.benefit. There was no current income tax expense or benefit in the first six months of 2016 compared to $0.9 million for the first six months of 2015.2017 or 2016. We did not pay any income taxes in the first six months of 2016.2017.

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, in the future 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 our legal proceedings involving us will not materially affect our financial results;

our ability to timely secure third-party services used in completing our wells;
our ability to transport or convey our oil or natural gas production to established pipeline systems;
impact of federal and state legislative and regulatory initiatives relating to hydrocarbon fracturing impacting our costs and increasing operating restrictions or delays as well as other adverse impacts on our business;
our projected production guidelines for the year;
our anticipated capital budgets;
our financial condition and liquidity;
the number of wells our oil and natural gas segment plans to drill or rework during the year; and
our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may be requiredhave to record in future periods.

These statements are based on certain assumptions and analyses made by us in light ofbased 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;
our ability to successfully implement our pending technology conversion process relating to our financialputative class action lawsuits that may result in substantial expenditures and operational information systems;divert management's attention; and
other factors, most of which are beyond our control.

You should not place undue reliance on any of these forward-looking statements. Except as required by law, we disclaim any current 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 six months 20162017 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 $464,000$392,000 per month ($5.6($4.7 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 $252,000$219,000 per month ($3.0($2.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices,

without the effect of hedging, would have a $399,000$362,000 per month ($4.8($4.3 million annualized) change in our pre-tax operating cash flow.

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

At June 30, 2016, we had2017, the following derivatives were outstanding:
Term Commodity Contracted Volume 
Weighted Average 
Fixed Price
 Contracted Market
Jul’16Jul’17Dec’16Oct'17 Natural gas – swap 45,00070,000 MMBtu/day $2.5963.038 IF – NYMEX (HH)
Jan’17Nov’17 – Dec'17 Natural gas – swap 60,000 MMBtu/day $2.960 IF – NYMEX (HH)
Jan’18 – Dec'18 Natural gas – swap 10,00020,000 MMBtu/day $3.0253.013 IF – NYMEX (HH)
Jan’17Nov’17 – Dec'17 Natural gas – basis swap 20,000 MMBtu/day $(0.215) IF – NYMEX (HH)
Jan’18 – Mar'18Natural gas – basis swap10,000 MMBtu/day$(0.208)IF – NYMEX (HH)
Nov’18 – Dec'18 Natural gas – basis swap 10,000 MMBtu/day $(0.208) IF – NYMEX (HH)
Jul’16 – Dec'16Natural gas – collar42,000 MMBtu/day$2.40 - $2.88IF – NYMEX (HH)
Jan’17Jul’17 – Oct'17 Natural gas – collar 10,00020,000 MMBtu/day $2.752.88 - $2.95$3.10 IF – NYMEX (HH)
Jul’16Jul'17Dec'16Natural gas – three-way collar13,500 MMBtu/day$2.70 - $2.20 - $3.26IF – NYMEX (HH)
Jan’17 – Dec'17Oct'17 Natural gas – three-way collar 15,000 MMBtu/day $2.50 - $2.00 - $3.32 IF – NYMEX (HH)
Jul’16Nov’17Sep'16Dec'17 Crude oil – swap1,000 Bbl/day$48.45WTI – NYMEX
Jul’16 – Sep'16Crude oil – collar2,450 Bbl/day$44.44 - $52.46WTI – NYMEX
Oct’16 – Dec'16Crude oil – collar1,450 Bbl/day$47.50 - $56.40WTI – NYMEX
Jul’16 – Dec'16Crude oilNatural gas – three-way collar 700 Bbl/25,000 MMBtu/day $46.502.90 - $35.00$2.30 - $57.00$3.59 WTIIF – NYMEX (HH)
Jul’16Jan'18Dec'16Mar'18 
Crude oilNatural gas – three-way collar(1)
 700 Bbl/60,000 MMBtu/day $47.503.29 - $35.00$2.63 - $63.50$4.07 WTIIF – NYMEX (HH)
Jan’17Apr'18 – Dec'18Natural gas – three-way collar20,000 MMBtu/day$3.00 - $2.50 - $3.51IF – NYMEX (HH)
Jul’17 – Dec'17 Crude oil – three-way collar 7503,750 Bbl/day$49.79 - $39.58 - $60.98WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar1,000 Bbl/day $50.00 - $37.50$40.00 - $63.90$56.65 WTI – NYMEX
_______________________
(1)We pay our counterparty a premium, which can be and is being deferred until settlement.

After June 30, 2016, we entered into2017, the following derivatives:derivatives were entered into:
Term Commodity Contracted Volume 
Weighted Average 
Fixed Price
 Contracted Market
Jan’17Jan'18Oct'17Dec'18 Natural gasCrude oil swap500 Bbl/day$50.00WTI – NYMEX
Jan'18 – Dec'18Crude oil – three-way collar 10,000 MMBtu/1,000 Bbl/day $3.0045.00 - $3.24$35.00 - $55.50 IFWTI – NYMEX (HH)

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreement 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 agreement may be fixed at the LIBOR Rate for periods of up to 180 days. Based on our average outstanding long-term debt subject to a variable rate in the first six months of 2016,2017, a 1% increase in the floating rate would reduce our annual pre-tax cash flow by approximately $2.4$1.6 million. Under our Notes, we pay a fixed rate of interest of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year).


Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures under Exchange Act Rule 13a-15. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of June 30, 20162017 in ensuring the appropriate information is recorded, processed, summarized and reported in our periodic SEC filings relating to the company (including its consolidated subsidiaries) and is accumulated and communicated to the Chief Executive Officer, Chief Financial Officer, and management to allow timely decisions.

Changes in Internal Controls. In January 2017, we implemented a new ERP accounting and reporting system designed to upgrade our technology and improve the timeliness and quality of our financial and operational information. This new ERP system was not implemented in response to any material weakness in our internal control over financial reporting. The

implementation of the ERP system has affected the processes that constitute part of our internal control over financial reporting and requires ongoing testing for effectiveness. The adoption of this new ERP system has not materially affected our internal controls over financial reporting. There were no changes in our internal controls over financial reporting during the quarter ended June 30, 20162017 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting, as defined in Rule 13a – 15(f) under the Exchange Act.

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

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

On March 11, 2016, a putative class action lawsuit was filed against Unit Petroleum Company styled Cockerell Oil Properties, Ltd., v. Unit Petroleum Company in LeFlore County, Oklahoma. We removed the case to federal court in the Eastern District of Oklahoma. The plaintiff alleges that Unit Petroleum wrongfully failed to pay interest with respect to untimely royalty payments under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of royalty owners in our Oklahoma wells. We have asserted several defenses including that the case cannot be properly certified as a class action because of the wide variety of circumstances that determine whether a royalty payment was timely made or has accrued interest under Oklahoma law. At this point, the court has not taken any action on the issue of class certification.

We continue to vigorously defend against each of the pending claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.

Item 1A. Risk Factors

In addition to the other information set forth in this quarterly report, you should carefully consider the factors discussed below, if any, and in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015,2016, 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, 2015.2016.

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

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

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

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

The following table provides information relating to our repurchase of common stock for the three months ended June 30, 2016:2017:
Period 
(a)
Total Number of Shares Purchased
 
(b)
Average Price Paid
Per Share
 
(c)
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs
 
(d)
Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
April 1, 20162017 to April 30, 20162017 
 $
 
 
May 1, 20162017 to May 31, 20162017 
 
 
 
June 1, 20162017 to June 30, 20162017 
 
 
 
Total 
 $
 
 
 

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.


Item 6. Exhibits

Exhibits:
 
10.1Form of Restricted Stock Agreement
31.1Certification of Chief Executive Officer under Rule 13a – 14(a) of the Exchange Act.
  
31.2Certification of Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act.
  
32Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act and 18 U.S.C. Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.
  
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.


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:August 9, 20163, 2017
By: /s/ Larry D. Pinkston
  LARRY D. PINKSTON
  Chief Executive Officer and Director
   
Date:August 9, 20163, 2017
By: /s/ David T. Merrill
  DAVID T. MERRILL
  
Senior Vice President, Chief Financial Officer,
and Treasurer


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