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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 March 31, 2019 
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]
WFX-20190331_G1.JPG
UNIT CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 73-1283193
(State or other jurisdiction of incorporation) (I.R.S. Employer Identification No.)

8200 South Unit Drive, Tulsa, Oklahoma 74132 
(Address of principal executive offices) (Zip Code)
(918) 493-7700
(Registrant’s telephone number, including area code)
None
(Former name, former address and former fiscal year,
if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes [x]            No [  ]  

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).       Yes [x]            No [  ]                                                   
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [ x ]   Accelerated filer [ ]    Non-accelerated filer [  ]
Smaller reporting company [  ]   Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]        

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [  ]            No [x]         
As of April 19, 2019, 55,467,987 shares of the issuer's common stock were outstanding.
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
Common Stock UNT NYSE



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1

Table of Contents
Forward-Looking Statements

This report contains “forward-looking statements” – meaning, statements related to future events within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included or incorporated by reference in this document that addresses activities, events or developments we expect or anticipate will or may occur, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are used to identify forward-looking statements. This report modifies and supersedes documents filed by us before this report. In addition, certain information we file with the SEC will automatically update and supersede information in this report.
 
These forward-looking statements include, among others, things as:

the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
prices for oil, natural gas liquids (NGLs), and natural gas;
demand for oil, NGLs, and natural gas;
our exploration and drilling prospects;
the estimates of our proved oil, NGLs, and natural gas reserves;
oil, NGLs, and natural gas reserve potential;
development and infill drilling potential;
expansion and other development trends of the oil and natural gas industry;
our business strategy;
our plans to maintain or increase production of oil, NGLs, and natural gas;
the number of gathering systems and processing plants we plan to construct or acquire;
volumes and prices for natural gas gathered and processed;
expansion and growth of our business and operations;
demand for our drilling rigs and drilling rig rates;
our belief that the final outcome of legal proceedings involving us will not materially affect our financial results;
our ability to timely secure third-party services used in completing our wells;
our ability to transport or convey our oil or natural gas production to established pipeline systems;
impact of federal and state legislative and regulatory actions affecting our costs and increasing operating restrictions or delays and other adverse impacts on our business;
our projected production guidelines for the year;
our anticipated capital budgets;
our financial condition and liquidity;
the number of wells our oil and natural gas segment plans to drill or rework during the year; and
our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods.
These statements are based on assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and expected future developments, and other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to several risks and uncertainties, any one or combination of which could cause our actual results to differ materially from our expectations and predictions, including:
the risk factors discussed in this document and in the documents (if any) we incorporate by reference;
general economic, market, or business conditions;
the availability of and nature of (or lack of) business opportunities we pursue;
demand for our land drilling services;
changes in laws or regulations;
changes in the current geopolitical situation;
risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
risks associated with future weather conditions;
decreases or increases in commodity prices;
putative class action lawsuits that may cause substantial expenditures and divert management's attention; and
other factors, most of which are beyond our control.
You should not place undue reliance on these forward-looking statements. Except as required by law, we disclaim any intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after this document to reflect unanticipated events.
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Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31,
2019
December 31,
2018
  (In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 3,891  $ 6,452 
Accounts receivable, net of allowance for doubtful accounts of $2,531 at both March 31, 2019 and December 31, 2018, respectively  93,875  119,397 
Materials and supplies 495  473 
Curent derivative asset (Note 10) 3,464  12,870 
Income taxes receivable 2,054  2,054 
Assets held for sale (Note 3) 19,728  22,511 
Prepaid expenses and other 7,504  6,602 
Total current assets 131,011  170,359 
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties 6,104,092  6,018,568 
Unproved properties not being amortized 339,957  330,216 
Drilling equipment 1,279,735  1,284,419 
Gas gathering and processing equipment 781,970  767,388 
Saltwater disposal systems 69,010  68,339 
Corporate land and building 59,080  59,081 
Transportation equipment 30,327  29,524 
Other 57,624  57,507 
8,721,795  8,615,042 
Less accumulated depreciation, depletion, amortization, and impairment 6,225,220  6,182,726 
Net property and equipment 2,496,575  2,432,316 
Goodwill 62,808  62,808 
Right of use asset (Note 12) 4,551  — 
Other assets 34,235  32,570 
Total assets (1)
$ 2,729,180  $ 2,698,053 

The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED

March 31,
2019
December 31,
2018
  (In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 132,899  $ 149,945 
Accrued liabilities (Note 5) 48,084  49,664 
Current operating lease liability (Note 12) 2,369  — 
Current portion of other long-term liabilities (Note 6) 14,310  14,250 
Total current liabilities 197,662  213,859 
Long-term debt less debt issuance costs (Note 6) 685,031  644,475 
Non-current derivative liability (Note 10) 475  293 
Operating lease liability (Note 12) 1,952  — 
Other long-term liabilities (Note 6) 103,832  101,234 
Deferred income taxes 144,369  144,748 
Commitments and contingencies (Note 13) —  — 
Shareholders’ equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued —  — 
Common stock, $.20 par value, 175,000,000 shares authorized, 55,467,987 and 54,055,600 shares issued as of March 31, 2019 and December 31, 2018, respectively  10,578  10,414 
Capital in excess of par value 633,361  628,108 
Accumulated other comprehensive loss (Note 15) (457) (481)
Retained earnings 749,510  752,840 
Total shareholders’ equity attributable to Unit Corporation 1,392,992  1,390,881 
Non-controlling interests in consolidated subsidiaries 202,867  202,563 
Total shareholders' equity 1,595,859  1,593,444 
Total liabilities(1) and shareholders’ equity
$ 2,729,180  $ 2,698,053 
_______________________
(1)Unit Corporation's consolidated total assets as of March 31, 2019 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $28.9 million and $428.1 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of March 31, 2019 include total current and long-term liabilities of the VIE of $36.0 million and $14.0 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2018 include total current and long-term assets of the VIE of $40.1 million and $423.3 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2018 include total current and long-term liabilities of the VIE of $42.8 million and $14.7 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 14 – Variable Interest Entity Arrangements.


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

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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
Three Months Ended
  March 31,
  2019  2018 
  (In thousands except per share amounts)
Revenues:
Oil and natural gas $ 86,095  $ 103,099 
Contract drilling 51,155  45,989 
Gas gathering and processing 52,441  56,044 
Total revenues 189,691  205,132 
Expenses:
Operating costs:
Oil and natural gas 32,714  35,962 
Contract drilling 31,401  31,667 
Gas gathering and processing 39,355  41,604 
Total operating costs 103,470  109,233 
Depreciation, depletion, and amortization 62,126  57,066 
General and administrative 9,741  10,762 
(Gain) loss on disposition of assets 1,615  (161)
Total operating expenses 176,952  176,900 
Income from operations 12,739  28,232 
Other income (expense):
Interest, net (8,538) (10,004)
Loss on derivatives
(6,932) (6,762)
Other, net
Total other income (expense) (15,465) (16,760)
Income (loss) before income taxes (2,726) 11,472 
Income tax expense (benefit):
Deferred (444) 3,607 
Total income taxes (444) 3,607 
Net income (loss) (2,282) 7,865 
Net income attributable to non-controlling interest 1,222  — 
Net income (loss) attributable to Unit Corporation $ (3,504) $ 7,865 
Net income (loss) attributable to Unit Corporation per common share:
Basic $ (0.07) $ 0.15 
Diluted $ (0.07) $ 0.15 

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

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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
 
Three Months Ended
  March 31,
  2019  2018 
  (In thousands) 
Net income (loss) $ (2,282) $ 7,865 
Other comprehensive income (loss), net of taxes:
Unrealized gain (loss) on securities, net of tax of $7 and ($58)  24  (176)
Comprehensive income (loss) (2,258) 7,689 
Less: Comprehensive income attributable to non-controlling interest
1,222  — 
Comprehensive income (loss) attributable to Unit Corporation $ (3,480) $ 7,689 

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

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

Shareholders' Equity Attributable to Unit Corporation
Common
Stock
Capital In Excess
of Par Value
Accumulated Other Comprehensive Income (Loss) Retained
Earnings
Non-controlling Interest in Consolidated Subsidiaries Total
  (In thousands except per share amounts)
Balances, December 31, 2018 $ 10,414  $ 628,108  $ (481) $ 752,840  $ 202,563  1,593,444 
Cumulative effect adjustment for adoption of ASUs (Notes 1 and 12)
—  —  —  174  —  174 
Net income (loss) —  —  —  (3,504) 1,222  (2,282)
Other comprehensive gain (net of tax of $7)
—  —  24  —  —  24 
Total comprehensive loss
(2,258)
Distributions to non-controlling interest —  —  —  —  (918) (918)
Activity in employee compensation plans (1,412,387 shares) 164  5,253  —  —  —  5,417 
Balances, March 31, 2019 $ 10,578  $ 633,361  $ (457) $ 749,510  $ 202,867  $ 1,595,859 

Shareholders' Equity Attributable to Unit Corporation
Common
Stock
Capital In Excess
of Par Value
Accumulated Other Comprehensive Income (Loss) Retained
Earnings
Non-controlling Interest in Consolidated Subsidiaries Total
  (In thousands except per share amounts)
Balances, December 31, 2017 $ 10,280  $ 535,815  $ 63  $ 799,402  $ —  $ 1,345,560 
Cumulative effect adjustment for adoption of ASUs —  —  13  (1,274) —  (1,261)
Net income —  —  —  7,865  —  7,865 
Other comprehensive loss (net of tax of ($58))
—  —  (176) —  —  (176)
Total comprehensive income
7,689 
Activity in employee compensation plans (1,166,227 shares) 123  5,189  —  —  —  5,312 
Balances, March 31, 2018 $ 10,403  $ 541,004  $ (100) $ 805,993  $ —  $ 1,357,300 

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


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UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended
  March 31,
  2019  2018 
  (In thousands)
OPERATING ACTIVITIES:
Net income (loss) $ (2,282) $ 7,865 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization 62,126  57,066 
Amortization of debt issuance costs and debt discount (Note 6) 556  546 
Loss on derivatives (Note 10) 6,932  6,762 
Cash proceeds (payments) on derivatives settled, net (Note 10) 2,656  (2,073)
Deferred tax expense (444) 3,607 
(Gain) loss on disposition of assets 1,615  (161)
Stock compensation plans 5,134  6,609 
Contract assets and liabilities, net (Note 2) (700) (1,192)
Other, net 573  937 
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable 18,830  8,005 
Accounts payable (20,848) (10,716)
Material and supplies (22) 50 
Accrued liabilities 2,749  6,757 
Other, net 203  (494)
Net cash provided by operating activities 77,078  83,568 
INVESTING ACTIVITIES:
Capital expenditures (122,507) (90,249)
Producing properties and other acquisitions (1,580) — 
Proceeds from disposition of assets 3,190  22,084 
Net cash used in investing activities (120,897) (68,165)
FINANCING ACTIVITIES:
Borrowings under credit agreement 109,800  67,400 
Payments under credit agreement (69,800) (97,700)
Payments on finance leases (985) (946)
Distributions to non-controlling interest (918) — 
Book overdrafts 3,161  15,894 
Net cash provided by (used in) financing activities 41,258  (15,352)
Net increase (decrease) in cash and cash equivalents (2,561) 51 
Cash and cash equivalents, beginning of period 6,452  701 
Cash and cash equivalents, end of period $ 3,891  $ 752 

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



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

Three Months Ended
  March 31,
  2019  2018
  (In thousands)
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)
$ (3,307) $ (1,731)
Income taxes
—  — 
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
(641) (13,238)
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations
(3,070) 6,340 

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

NOTE 1 – BASIS OF PREPARATION AND PRESENTATION

The unaudited condensed consolidated financial statements in this report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires. We consolidate the activities of Superior Pipeline Company, L.L.C. (Superior), a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, which qualifies as a Variable Interest Entity (VIE) under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power, through our 50% ownership, to direct those activities that most significantly affect the economic performance of Superior as further described in Note 14 – Variable Interest Entity Arrangements. 

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

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

Balance Sheets at March 31, 2019 and December 31, 2018;
Statements of Operations for the three months ended March 31, 2019 and 2018;
Statements of Comprehensive Income (Loss) for the three months ended March 31, 2019 and 2018;
Statements of Changes in Shareholders' Equity for the three months ended March 31, 2019 and 2018; and
Statements of Cash Flows for the three months ended March 31, 2019 and 2018.

Our financial statements are prepared in conformity with GAAP, which requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and notes. Actual results may differ from those estimates. Results for the three months ended March 31, 2019 and 2018 are not necessarily indicative of the results we may realize for the full year of 2019, or that we realized for the full year of 2018.

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

Accounting Changes - Recent Accounting Pronouncements - Adopted

As of January 1, 2019, we adopted Leases - Topic 842 (ASC 842) using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are not adjusted and continue to be reported under the accounting standards in effect for those periods. This new lease standard is explained further in Note 8 – New Accounting Pronouncements.

The additional disclosures required by ASC 842 have been included in Note 12 – Leases.

NOTE 2 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is our disaggregation of revenue and how our segment revenue is reported (as reflected in Note 16 – Industry Segment Information). Revenue from the oil and natural gas segment is from sales of our oil and natural gas production. Revenue from the contract drilling segment is derived by contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on time period. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas production and selling those commodities. We sell the hydrocarbons (from the oil and natural gas and mid-stream segments) to mid-stream and downstream oil and gas companies.

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Oil and Natural Gas Revenues

Certain costs—as either a deduction from revenue or as an expense—is determined based on when control of the commodity is transferred to our customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing and transportation costs included as part of the contract price with the customer on transfer of control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity represent operating costs.

Contract Drilling Revenues

We evaluated the mobilization and de-mobilization charges due on our outstanding drilling contracts. The impact of those charges to the financial statements was immaterial. As of March 31, 2019, we had 32 contract drilling contracts with terms ranging from two months to almost three years.

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

Mid-stream Contracts Revenues

Revenues are generated from the fees earned for gas gathering and processing services provided to a customer. The typical revenue contracts used by this segment are gas gathering and processing agreements. The following tables show the changes in our mid-stream contract asset and contract liability balances during the three months ended March 31, 2019:

Contract Assets Amount
(In thousands)
Balance at December 31, 2018 (1)
$ 13,164 
Amounts invoiced in excess of revenue recognized (9)
Balance at March 31, 2019 (1)
$ 13,155 
_______________________
1.At December 31, 2018, the total contract assets are included in prepaid expenses and other and other assets of $0.3 million and $12.9 million, respectively, in our Condensed Consolidated Balance Sheet. At March 31, 2019, the total contract assets included prepaid expenses and other and other assets of $1.8 million and $11.4 million, respectively, in our Condensed Consolidated Balance Sheet.

Contract Liabilities Amount
(In thousands)
Balance at December 31, 2018 $ 9,882 
Revenue recognized included in beginning balance (709)
Balance at March 31, 2019 $ 9,173 
_______________________
1.At December 31, 2018, the total contract liabilities are included in current portion of other long-term liabilities and other long-term liabilities of $2.9 million and $7.0 million, respectively, in our Condensed Consolidated Balance Sheet. At March 31, 2019, the total contract liabilities included current portion of other long-term liabilities and other long-term liabilities of $2.9 million and $6.3 million, respectively, in our Condensed Consolidated Balance Sheet.

Included below is the additional fixed revenue we will earn over the remaining term of the contracts and excludes all variable consideration to be earned with the associated contract.
Contract Remaining Term of Contract April - December 2019 2020 2021  2022  Total Remaining Impact to Revenue 
(In thousands) 
Demand fee contracts 3-4 years $ 1,932  $ (3,781) $ (3,507) $ 1,374  $ (3,982)

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NOTE 3 – DIVESTITURES

Oil and Natural Gas

We sold non-core oil and natural gas assets, net of related expenses, for $0.6 million during the first three months of 2019, compared to $21.7 million during the first three months of 2018. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

Contract Drilling

In December 2018, we removed 41 drilling rigs and other equipment from service. We estimated the fair value of the 41 drilling rigs based on the estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these estimates, we recorded a non-cash write-down of approximately $147.9 million, pre-tax. During the first quarter of 2019, we sold three of these drilling rigs and some of the other equipment to unaffiliated third parties. The proceeds of those sales, less costs to sell, was less than the applicable $2.8 million net book value resulting in a loss of $0.6 million. The remaining drilling rigs and equipment not sold will be marketed for sale throughout 2019 and remain classified as assets held for sale. The net book value of those assets is $19.7 million.

NOTE 4 – EARNINGS (LOSS) PER SHARE

Information related to the calculation of earnings (loss) per share attributable to Unit Corporation follows:
Earnings (Loss)
(Numerator)
Weighted
Shares
(Denominator)
Per-Share
Amount
  (In thousands except per share amounts)
For the three months ended March 31, 2019
Basic loss attributable to Unit Corporation per common share $ (3,504) 52,557  $ (0.07)
Effect of dilutive stock options and restricted stock
—  —  — 
Diluted loss attributable to Unit Corporation per common share $ (3,504) 52,557  $ (0.07)
For the three months ended March 31, 2018
Basic earnings attributable to Unit Corporation per common share $ 7,865  51,730  $ 0.15 
Effect of dilutive stock options and restricted stock
—  542 
Diluted earnings attributable to Unit Corporation per common share $ 7,865  52,272  $ 0.15 

Due to the net loss for the three months ended March 31, 2019, approximately 279,000 weighted average shares related to stock options and restricted stock were antidilutive and were excluded from the earnings per share calculation above.

The following table shows the number of stock options (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
Three Months Ended
  March 31,
  2019  2018 
Stock options 56,000  87,500 
Average exercise price $ 44.73  $ 51.34 

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NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of:
March 31,
2019
December 31,
2018
  (In thousands)
Interest payable $ 17,354  $ 6,635 
Employee costs 10,356  22,056 
Lease operating expenses 7,961  12,756 
Taxes 4,059  1,378 
Third-party credits 2,974  2,129 
Other 5,380  4,710 
Total accrued liabilities $ 48,084  $ 49,664 
 
NOTE 6 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

As of the date indicated, our long-term debt consisted of the following:
March 31,
2019
December 31,
2018
  (In thousands)
Unit credit agreement with an average interest rate of 4.0% at March 31, 2019 $ 40,000  $ — 
Superior credit agreement —  — 
6.625% senior subordinated notes due 2021 650,000  650,000 
Total principal amount 690,000  650,000 
Less: unamortized discount (1,464) (1,623)
Less: debt issuance costs, net (3,505) (3,902)
Total long-term debt $ 685,031  $ 644,475 

Unit Credit Agreement. On October 18, 2018, we amended our Senior Credit Agreement (Unit credit agreement) which is scheduled to mature on October 18, 2023. Under that 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 $1.0 billion. Our elected commitment amount is $425.0 million. Our borrowing base is $425.0 million. We are currently charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the total borrowing base. Total amendment fees of $3.3 million in origination, agency, syndication, and other related fees are being amortized over the life of the agreement. Under the agreement, we have pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties.

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

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

At our election, any part of the outstanding debt under the Unit credit agreement can be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base for the term plus 1.50% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the Unit credit agreement but in no event less than
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LIBOR plus 1.00% plus a margin. The credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At March 31, 2019, we had $40.0 million outstanding borrowings under the Unit credit agreement. 

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

The Unit credit agreement prohibits, among other things:

the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income for the preceding fiscal year; 
the incurrence of additional debt with certain limited exceptions;
the creation or existence of mortgages or liens, other than those in the ordinary course of business and with certain limited exceptions, on any of our properties, except in favor of our lenders; and
investments in Unrestricted Subsidiaries (as defined in the Unit credit agreement) over $200.0 million.

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

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

As of March 31, 2019, we were in compliance with these covenants. 

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

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

The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. The agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As of March 31, 2019, Superior was in compliance with these covenants. 
 
The borrowings under the Superior credit agreement will fund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior. As of March 31, 2019, we had no outstanding borrowings under the Superior credit agreement.

Superior's credit agreement is not guaranteed by Unit.

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

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

Unit, as the parent company, has no significant independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Effective April 3, 2018, Superior is no longer a Guarantor of the Notes. Excluding Superior, any of our other subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of our subsidiaries through dividends, loans, advances, or otherwise.

We may redeem all or, occasionally, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of March 31, 2019.

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

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
March 31,
2019
December 31,
2018
  (In thousands)
Asset retirement obligation (ARO) liability $ 67,840  $ 64,208 
Workers’ compensation 12,226  12,738 
Finance lease obligations 10,395  11,380 
Contract liability 9,173  9,881 
Separation benefit plans 9,291  8,814 
Deferred compensation plan 5,845  5,132 
Gas balancing liability 3,372  3,331 
118,142  115,484 
Less current portion 14,310  14,250 
Total other long-term liabilities $ 103,832  $ 101,234 

Estimated annual principal payments under the terms of our long-term debt and other long-term liabilities during the five successive twelve-month periods beginning April 1, 2019 (and through 2024) are $14.3 million, $47.8 million, $656.9 million, $3.6 million, and $42.3 million, respectively.

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NOTE 7 – ASSET RETIREMENT OBLIGATIONS

We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All our AROs relate to the plugging costs associated with our oil and gas wells.

 The following table shows certain information about our estimated AROs for the periods indicated:
Three Months Ended
  March 31,
  2019  2018 
  (In thousands)
ARO liability, January 1: $ 64,208  $ 69,444 
Accretion of discount 562  659 
Liability incurred 3,116  118 
Liability settled (1,636) (1,626)
Liability sold (549) (81)
Revision of estimates (1)
2,139 

(4,751)
ARO liability, March 31: 67,840  63,763 
Less current portion 1,742  1,477 
Total long-term ARO $ 66,098  $ 62,286 
_______________________ 
1.Plugging liability estimates were revised in both 2019 and 2018 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments. 

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS

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

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

Adopted Standards

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

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

The additional disclosures required by ASC 842 have been included in Note 12 – Leases.



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NOTE 9 – STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:
Three Months Ended
March 31,
2019  2018 
(In millions)
Recognized stock compensation expense $ 3.8  $ 5.5 
Capitalized stock compensation cost for our oil and natural gas properties
0.6  0.4 
Tax benefit on stock-based compensation 0.9  1.3 
 
The remaining unrecognized compensation cost related to unvested awards at March 31, 2019 is approximately $30.4 million, of which $4.2 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is 1.0 year.

Our Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) and to non-employee directors. 7,230,000 shares of the company's common stock are authorized for issuance to eligible participants under the amended plan with 2,000,000 shares being the maximum number of shares that can be issued as "incentive stock options."

We granted no SARs or stock options during either of the three month periods ending March 31, 2019 or 2018. This table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated:
Three Months Ended Three Months Ended
March 31, 2019 March 31, 2018
  Time
Vested
Performance Vested Time
Vested
Performance Vested
Shares granted:
Employees 925,673  424,070  839,498  362,070 
Non-employee directors —  —  —  — 
925,673  424,070  839,498  362,070 
Estimated fair value (in millions):(1)
Employees $ 14.6  $ 7.1  $ 16.1  $ 7.3 
Non-employee directors —  —  —  — 
$ 14.6  $ 7.1  $ 16.1  $ 7.3 
Percentage of shares granted expected to be distributed:
Employees 95  % 64  % 95  % 63  %
Non-employee directors N/A    N/A    N/A    N/A   
_______________________
1.The performance shares represent 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

The time vested restricted stock awards granted during the first three months of 2019 and 2018 are being recognized over a three-year vesting period. During the first quarter of 2019 and 2018, two performance vested restricted stock awards were 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 (TSR) at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three-year vesting period subject to the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected TSR performance criteria at March 31, 2019, the participants are estimated to receive 28% of the 2019 and 74% of the 2018 performance-based shares. The CFTA performance measurement at March 31, 2019 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 2019 awards for the first three months of 2019 was $1.0 million. 

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NOTE 10 – DERIVATIVES

Commodity Derivatives

We have signed various types of derivative transactions covering some of our projected natural gas and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of March 31, 2019, these hedges made up our derivative transactions:

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

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

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

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

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

At March 31, 2019, these derivatives were outstanding:
Term Commodity Contracted Volume Weighted Average 
Fixed Price
Contracted Market
Apr'19 – Oct'19 Natural gas – swap 60,000 MMBtu/day $2.900  IF – NYMEX (HH)
Nov'19 – Dec'19 Natural gas – swap 40,000 MMBtu/day $2.900  IF – NYMEX (HH)
Apr'19 – Dec'19 Natural gas – basis swap 20,000 MMBtu/day $(0.659) PEPL
Apr'19 – Dec'19 Natural gas – basis swap 10,000 MMBtu/day $(0.625) NGL MIDCON
Apr'19 – Dec'19 Natural gas – basis swap 30,000 MMBtu/day $(0.265) NGPL TEXOK
Jan'20 – Dec'20 Natural gas – basis swap 30,000 MMBtu/day $(0.275) NGPL TEXOK
Apr'19 – Dec'19 Natural gas – collar 20,000 MMBtu/day $2.63 - $3.03 IF – NYMEX (HH)
Apr'19 – Dec'19 Crude oil – three-way collar 4,000 Bbl/day $61.25 - $51.25 - $72.93 WTI – NYMEX

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The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
    Derivative Assets
    Fair Value
  Balance Sheet Location March 31,
2019
December 31,
2018
    (In thousands)
Commodity derivatives:
Current Current derivative asset $ 3,464  $ 12,870 
Long-term Non-current derivative asset —  — 
Total derivative assets $ 3,464  $ 12,870 

    Derivative Liabilities
    Fair Value
  Balance Sheet Location March 31,
2019
December 31,
2018
    (In thousands)
Commodity derivatives:
Current Current derivative liability $ —  $ — 
Long-term Non-current derivative liability 475  293 
Total derivative liabilities $ 475  $ 293 

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

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31:
Derivatives Instruments Location of Gain (Loss) Recognized in
Income on Derivative
Amount of Gain 
(Loss) Recognized in Income on Derivative
    2019  2018 
    (In thousands)
Commodity derivatives
Loss on derivatives (1)
$ (6,932) $ (6,762)
Total $ (6,932) $ (6,762)
_______________________
1.Amounts settled during the 2019 and 2018 periods include net proceeds of $2.7 million and net payments of  $2.1 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:
March 31, 2019 $ 830  $ —  $ 605  $ 225 
December 31, 2018 $ 830  $ —  $ 636  $ 194 

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

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

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

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

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

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

The following tables set forth our recurring fair value measurements:
  March 31, 2019
  Level 1 Level 2 Level 3 Effect
of Netting
Net Amounts Presented
  (In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets $ —  $ 1,727  $ 3,098  $ (1,361) $ 3,464 
Liabilities —  (1,818) (18) 1,361  (475)
Total commodity derivatives —  (91) 3,080  —  2,989 
Equity securities 225  —  —  —  225 
$ 225  $ (91) $ 3,080  $ —  $ 3,214 

  December 31, 2018
  Level 1 Level 2 Level 3 Effect
of Netting
Net Amounts Presented
  (In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets $ —  $ 3,225  $ 10,964  $ (1,319) $ 12,870 
Liabilities —  (1,278) (334) 1,319  (293)
Total commodity derivatives —  1,947  10,630  —  12,577 
Equity securities 194  —  —  —  194 
$ 194  $ 1,947  $ 10,630  $ —  $ 12,771 

All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties and no collateral has been posted as of March 31, 2019.

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

Level 1 Fair Value Measurements

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

Level 2 Fair Value Measurements

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

Level 3 Fair Value Measurements

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

The following table is a reconciliation of our level 3 fair value measurements: 
  Net Derivatives
Three Months Ended
March 31,
  2019 2018
  (In thousands)
Beginning of period $ 10,630  $ (206)
Total gains or losses (realized and unrealized):
Included in earnings (1)
(5,434) (3,919)
Settlements (2,116) 919 
End of period $ 3,080  $ (3,206)
Total losses for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period
$ (7,550) $ (3,000)
_______________________
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 March 31, 2019:
Commodity (1)
Fair Value Valuation Technique Unobservable Input Range
  (In thousands)      
Oil three-way collars $ 3,096  Discounted cash flow Forward commodity price curve $0 - $7.93
Natural gas collars $ (16) Discounted cash flow Forward commodity price curve $0 - $0.13
 _______________________
1.The commodity contracts detailed in this category include non-exchange-traded crude oil three-way collars and natural gas collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Our valuation at March 31, 2019 reflected that the risk of non-performance was immaterial.

Fair Value of Other Financial Instruments

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

At March 31, 2019, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (composed of bank and money market accounts - classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature.

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Based on the borrowing rates available to us for credit agreement debt with similar terms and maturities and considering the risk of our non-performance, long-term debt under the Unit and Superior credit agreements approximate their fair value and at March 31, 2019 we had $40.0 million of outstanding borrowings under the Unit and none under the Superior credit agreementsWe had no borrowing under either the Unit or Superior Credit agreements at December 31, 2018. Borrowings under these agreements are classified as Level 2.

The carrying amounts of long-term debt associated with the Notes, net of unamortized discount and debt issuance costs, reported in the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018 were $645.0 million and $644.5 million, respectively. We estimate the fair value of the Notes using quoted marked prices at March 31, 2019 and December 31, 2018 was $626.0 million and $600.5 million, respectively. The Notes would be classified as Level 2.

Fair Value of Non-Financial Instruments

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

NOTE 12 – LEASES

Operating Leases under ASC 840

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

Operating Leases under ASC 842

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

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

Related to our oil and natural gas segment, our short-term lease costs include those that are recognized in profit or loss during the period and those that are capitalized as part of the cost of another asset in accordance with other U.S. GAAP. As the costs related to our drilling and production activities are reflected at our net ownership consistent with the principals of proportional consolidation, and lease commitments are generally considered gross as the operator, the costs may not reasonably reflect the Company’s short-term lease commitments. As of March 31, 2019, we had an average working interest of 87% in our operated properties. 

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

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

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

Adoption. Adoption of Topic 842 resulted in new operating lease assets and lease liabilities on our Unaudited Condensed Consolidated Balance Sheet of $3.7 million and $3.5 million, respectively, as of January 1, 2019, which represents noncash operating activity. The immaterial difference between the lease assets and lease liabilities was recorded as an adjustment to the beginning balance of retained earnings, which represents the cumulative impact of adopting the standard. Our accounting for finance leases remained substantially unchanged. Adoption of Topic 842 will not materially impact our Company's results of operations or cash flows.

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

The following table shows supplemental cash flow information related to leases for the three months of March 31, 2019:
Amount
(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases $ 577 
Financing cash flows for finance leases 985 
Lease liabilities recognized in exchange for new operating lease right of use assets

The following table shows information about our lease assets and liabilities included in our Unaudited Condensed Consolidated Balance Sheet as of March 31, 2019:
Classification on the Consolidated Balance Sheet March 31,
2019
(In thousands)
Assets
Operating right of use assets Right of use assets $ 4,551 
Finance right of use assets Property, plant, and equipment, net 18,886 
Total right of use assets $ 23,437 
Liabilities
Current liabilities:
Operating lease liabilities Current operating lease liabilities $ 2,369 
Finance lease liabilities Current portion of other long-term liabilities 4,041 
Non-current liabilities:
Operating lease liabilities Operating lease liabilities 1,952 
Finance lease liabilities Other long-term liabilities 6,354 
Total lease liabilities $ 14,716 

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The following table shows certain information related to the lease costs for our finance and operating leases for the three months ended March 31, 2019:
Amount
(In thousands)
Components of total lease cost:
Amortization of finance leased assets $ 985 
Interest on finance lease liabilities 111 
Operating lease cost 598 
Short-term lease cost (1)
9,974 
Variable lease cost 106 
Total lease cost $ 11,774 
_______________________
1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $5.7 million.

The following table shows certain information related to the weighted average remaining lease terms and the weighted average discount rates for our operating and finance leases:
Weighted Average Remaining Lease Term
Weighted average discount rate (1)
(In years)
Operating leases 2.5 6.18%   
Finance leases 2.4 4.00%   
_______________________
1.Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.

The following table sets forth the maturity of our operating lease liabilities as of March 31, 2019:
Amount
(In thousands)
Ending April 1,
2020 $ 2,582 
2021 1,409 
2022 550 
2023 12 
2024 12 
2025 and beyond 84 
Total future payments 4,649 
Less: Interest 328 
Present value of future minimum operating lease payments 4,321 
Less: Current portion 2,369 
Total long-term operating lease payments $ 1,952 

As of March 31, 2019, we had additional leases that have not yet commenced of $1.7 million. These leases will commence in 2019 with lease terms of one to three years.

Finance Leases 

In 2014, Superior entered into finance lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $4.0 million current portion of the finance lease obligations is included in current portion of other long-term liabilities and the non-current portion of $6.4 million is included in
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other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of March 31, 2019. These finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $3.7 million and $0.5 million, respectively, at March 31, 2019. Annual payments, net of maintenance and interest, average $4.3 million annually through 2021. At the end of the term, Superior has the option to purchase the assets at 10% of their then fair market value.

The following table sets forth the maturity of our finance lease liabilities as of March 31, 2019:
Amount
Ending April 1, (In thousands)
2020  $ 6,195 
2021  7,841 
2022  579 
Total future payments 14,615 
Less payments related to:
Maintenance 3,695 
Interest 525 
Present value of future minimum finance lease payments 10,395 
Less: Current portion 4,041 
Total long-term finance lease payments $ 6,354 

NOTE 13 – COMMITMENTS AND CONTINGENCIES

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 three months of 2019 or 2018.

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

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

During the second quarter of 2018, as part of the Superior transaction, we entered into a contractual obligation that commits us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. This amount is included in our future drilling plans. For each dollar of the $150.0 million that we do not spend (over the three year period), we would forgo receiving $0.58 of future distributions from our 50% ownership interest in our consolidated mid-stream subsidiary. If we elected not to drill or spend any money in the designated area over the three year period, the maximum amount we could forgo from distributions would be $87.0 million. Total spent towards the $150.0 million as of March 31, 2019 was $8.3 million.

For the next 12 months, we have committed to purchase approximately $4.0 million of new drilling rig components.

NOTE 14 – VARIABLE INTEREST ENTITY ARRANGEMENTS

On April 3, 2018 we sold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior will be governed and managed under the Amended and Restated Limited Liability Company Agreement and the MSA. The MSA is between our affiliate, SPC Midstream Operating, L.L.C. (the
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Operator) and Superior. The Operator is owned 100% by Unit Corporation. Under the guidance in ASC 810, Consolidation, we have determined that Superior is a VIE. The two variable interests applicable to Unit include the 50% equity investment in Superior and the MSA. The MSA houses the power to direct the activities that most significantly impact Superior's operating performance. The MSA is a separate variable interest. Unit through the MSA has the power to direct Superior’s most significant activities; reciprocally the equity investors lack the power to direct the activities that most significantly impact the entity’s economic performance. Because of this, Unit is considered the primary beneficiary. There have been no changes to the primary beneficiary during the quarter ended March 31, 2019.

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

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

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

The carrying value of Superior's assets and liabilities, after eliminations of any intercompany transactions and balances, in the consolidated balance sheets were as follows:
March 31,
2019
December 31,
2018
  (In thousands)
Current assets:
Cash and cash equivalents $ 3,128  $ 5,841 
Accounts receivable  23,331  33,207 
Prepaid expenses and other 2,446  1,049 
Total current assets 28,905  40,097 
Property and equipment:
Gas gathering and processing equipment 781,970  767,388 
Transportation equipment 3,264  3,086 
785,234  770,474 
Less accumulated depreciation, depletion, amortization, and impairment 376,006  364,740 
Net property and equipment 409,228  405,734 
Right of use asset 2,779  — 
Other assets 16,048  17,551 
Total assets $ 456,960  $ 463,382 
Current liabilities:
Accounts payable $ 24,246  $ 32,214 
Accrued liabilities 3,153  3,688 
Current operating lease liability 1,702  — 
Current portion of other long-term liabilities 6,923  6,875 
Total current liabilities 36,024  42,777 
Long-term debt less debt issuance costs —  — 
Operating lease liability 937  — 
Other long-term liabilities 13,048  14,687 
Total liabilities $ 50,009  $ 57,464 

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NOTE 15 – EQUITY
 
Accumulated Other Comprehensive Income (Loss)

Components of accumulated other comprehensive income (loss) were as follows for the three months ended March 31:
2019  2018 
(In thousands)
Unrealized appreciation (loss) on securities, before tax $ 31  $ (234)
Tax benefit (expense) (7) 58 
(1)
Unrealized appreciation (loss) on securities, net of tax $ 24  $ (176)
_______________________
1.Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Changes in accumulated other comprehensive income by component, net of tax, for the three months ended March 31 are as follows:
Net Gains on Equity Securities
2019  2018 
(In thousands)
Balance at December 31: $ (481) $ 63 
Adjustment due to ASU 2018-02 —  13 
(1)
Balance at January 1: (481) 76 
Unrealized appreciation (loss) before reclassifications 24  (176)
(1)
Amounts reclassified from accumulated other comprehensive income —  — 
Net current-period other comprehensive income (loss) 24  (176)
Balance at March 31: $ (457) $ (100)
_______________________
1.Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

NOTE 16 – INDUSTRY SEGMENT INFORMATION

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

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

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

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The following tables provide certain information about the operations of each of our segments:
Three Months Ended March 31, 2019
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues: (1)
Oil and natural gas $ 86,095  $ —  $ —  $ —  $ —  $ 86,095 
Contract drilling —  58,199  —  —  (7,044) 51,155 
Gas gathering and processing —  —  70,509  —  (18,068) 52,441 
Total revenues 86,095  58,199  70,509  —  (25,112) 189,691 
Expenses:
Operating costs:
Oil and natural gas 34,008  —  —  —  (1,294) 32,714 
Contract drilling —  37,385  —  —  (5,984) 31,401 
Gas gathering and processing —  —  56,129  —  (16,774) 39,355 
Total operating costs
34,008  37,385  56,129  —  (24,052) 103,470 
Depreciation, depletion, and amortization
35,767  12,699  11,726  1,934  —  62,126 
Total expenses 69,775  50,084  67,855  1,934  (24,052) 165,596 
General and administrative
—  —  —  9,741  —  9,741 
(Gain) loss on disposition of assets (79) 1,746  (42) (10) —  1,615 
Income (loss) from operations 16,399  6,369  2,696  (11,665) (1,060) 12,739 
Loss on derivatives —  —  —  (6,932) —  (6,932)
Interest, net —  —  (336) (8,202) —  (8,538)
Other —  —  —  — 
Income (loss) before income taxes
$ 16,399  $ 6,369  $ 2,360  $ (26,794) $ (1,060) $ (2,726)
_______________________
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

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Three Months Ended March 31, 2018
  Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
  (In thousands)
Revenues: (1)
Oil and natural gas $ 103,099  $ —  $ —  $ —  $ —  $ 103,099 
Contract drilling —  50,710  —  —  (4,721) 45,989 
Gas gathering and processing —  —  74,650  —  (18,606) 56,044 
Total revenues 103,099  50,710  74,650  —  (23,327) 205,132 
Expenses:
Operating costs:
Oil and natural gas 37,152  —  —  —  (1,190) 35,962