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Table of Contents
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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]
UNT-20190630_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 ☒            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 ☒            No ☐                                                   
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ☒   Accelerated filer ☐    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 ☒         
As of July 19, 2019, 55,536,916 shares of the issuer's common stock were outstanding.
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
Common Stock UNT NYSE



Table of Contents
TABLE OF CONTENTS
 
    Page
Number
Item 1.
3
5
6
7
9
11
Item 2.
43
Item 3.
65
Item 4.
66
Item 1.
67
Item 1A.
68
Item 2.
68
Item 3.
68
Item 4.
68
Item 5.
68
Item 6.
69
70

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 (including our ability to refinance our senior subordinated notes);
the number of wells our oil and natural gas segment plans to drill or rework during the year; and
our 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.
2

Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30,
2019
December 31,
2018
  (In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 669  $ 6,452 
Accounts receivable, net of allowance for doubtful accounts of $2,494 and $2,531 at June 30, 2019 and December 31, 2018, respectively  89,876  119,397 
Materials and supplies 516  473 
Current derivative asset (Note 10) 8,513  12,870 
Income taxes receivable 2,405  2,054 
Assets held for sale (Note 3) 19,500  22,511 
Prepaid expenses and other 9,106  6,602 
Total current assets 130,585  170,359 
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties 6,212,323  6,018,568 
Unproved properties not being amortized 336,214  330,216 
Drilling equipment 1,284,295  1,284,419 
Gas gathering and processing equipment 798,503  767,388 
Saltwater disposal systems 69,212  68,339 
Corporate land and building 59,080  59,081 
Transportation equipment 30,019  29,524 
Other 57,900  57,507 
8,847,546  8,615,042 
Less accumulated depreciation, depletion, amortization, and impairment 6,289,575  6,182,726 
Net property and equipment 2,557,971  2,432,316 
Goodwill 62,808  62,808 
Right of use asset (Note 12) 8,302  — 
Other assets 33,863  32,570 
Total assets (1)
$ 2,793,529  $ 2,698,053 

The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
3

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

June 30,
2019
December 31,
2018
  (In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 131,129  $ 149,945 
Accrued liabilities (Note 5) 45,175  49,664 
Current operating lease liability (Note 12) 4,519  — 
Current portion of other long-term liabilities (Note 6) 13,887  14,250 
Total current liabilities 194,710  213,859 
Long-term debt less debt issuance costs (Note 6) 756,590  644,475 
Non-current derivative liability (Note 10) 256  293 
Operating lease liability (Note 12) 3,556  — 
Other long-term liabilities (Note 6) 102,700  101,234 
Deferred income taxes 142,485  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, 55,536,916 and 54,055,600 shares issued as of June 30, 2019 and December 31, 2018, respectively  10,590  10,414 
Capital in excess of par value 638,769  628,108 
Accumulated other comprehensive loss (Note 15) (487) (481)
Retained earnings 741,001  752,840 
Total shareholders’ equity attributable to Unit Corporation 1,389,873  1,390,881 
Non-controlling interests in consolidated subsidiaries 203,359  202,563 
Total shareholders' equity 1,593,232  1,593,444 
Total liabilities(1) and shareholders’ equity
$ 2,793,529  $ 2,698,053 
_______________________
(1)Unit Corporation's consolidated total assets as of June 30, 2019 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $23.7 million and $435.4 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of June 30, 2019 include total current and long-term liabilities of the VIE of $29.6 million and $21.4 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2018 include total current and long-term assets of the VIE of $40.1 million and $423.3 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2018 include total current and long-term liabilities of the VIE of $42.8 million and $14.7 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 14 – Variable Interest Entity Arrangements.


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

4

Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
Three Months Ended Six Months Ended
  June 30, June 30,
  2019  2018  2019  2018 
  (In thousands except per share amounts)
Revenues:
Oil and natural gas $ 77,815  $ 102,318  $ 163,910  $ 205,417 
Contract drilling 43,037  46,926  94,192  92,915 
Gas gathering and processing 44,294  54,059  96,735  110,103 
Total revenues 165,146  203,303  354,837  408,435 
Expenses:
Operating costs:
Oil and natural gas 36,242  32,418  68,956  68,380 
Contract drilling 29,308  31,894  60,709  63,561 
Gas gathering and processing 32,491  39,703  71,846  81,307 
Total operating costs 98,041  104,015  201,511  213,248 
Depreciation, depletion, and amortization 66,292  58,373  128,418  115,439 
General and administrative 10,064  8,712  19,805  19,474 
(Gain) loss on disposition of assets (422) (161) 1,193  (322)
Total operating expenses 173,975  170,939  350,927  347,839 
Income (loss) from operations (8,829) 32,364  3,910  60,596 
Other income (expense):
Interest, net (8,995) (7,729) (17,533) (17,733)
Gain (loss) on derivatives
7,927  (14,461) 995  (21,223)
Other, net 11  11 
Total other income (expense) (1,062) (22,185) (16,527) (38,945)
Income (loss) before income taxes (9,891) 10,179  (12,617) 21,651 
Income tax expense (benefit):
Deferred (1,874) 2,029  (2,318) 5,636 
Total income taxes (1,874) 2,029  (2,318) 5,636 
Net income (loss) (8,017) 8,150  (10,299) 16,015 
Net income attributable to non-controlling interest 492  2,362  1,714  2,362 
Net income (loss) attributable to Unit Corporation $ (8,509) $ 5,788  (12,013) 13,653 
Net income (loss) attributable to Unit Corporation per common share (Note 4):
Basic $ (0.16) $ 0.11  $ (0.23) $ 0.26 
Diluted $ (0.16) $ 0.11  $ (0.23) $ 0.26 

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

5

Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
 
Three Months Ended Six Months Ended
  June 30, June 30,
  2019  2018  2019  2018 
  (In thousands) 
Net income (loss) $ (8,017) $ 8,150  $ (10,299) $ 16,015 
Other comprehensive income (loss), net of taxes:
Unrealized gain (loss) on securities, net of tax of ($9), $11, ($2) and ($47)  (30) 35  (6) (141)
Comprehensive income (loss) (8,047) 8,185  (10,305) 15,874 
Less: Comprehensive income attributable to non-controlling interest
492  2,362  1,714  2,362 
Comprehensive income (loss) attributable to Unit Corporation $ (8,539) $ 5,823  $ (12,019) $ 13,512 

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

6

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

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

Six Months Ended June 30, 2019
Shareholders' Equity Attributable to Unit Corporation
Common
Stock
Capital In Excess
of Par Value
Accumulated Other Comprehensive Income (Loss) Retained
Earnings
Non-controlling Interest in Consolidated 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) —  —  —  (12,013) 1,714  (10,299)
Other comprehensive loss (net of tax of ($2))
—  —  (6) —  —  (6)
Total comprehensive loss
(10,305)
Distributions to non-controlling interest
—  —  —  —  (918) (918)
Activity in employee compensation plans (1,481,316 shares)
176  10,661  —  —  —  10,837 
Balances, June 30, 2019 $ 10,590  $ 638,769  $ (487) $ 741,001  $ 203,359  $ 1,593,232 


7

Three Months Ended June 30, 2018 
Shareholders' Equity Attributable to Unit Corporation
Common
Stock
Capital In Excess
of Par Value
Accumulated Other Comprehensive Income (Loss) Retained
Earnings
Non-controlling Interest in Consolidated Subsidiaries Total
(In thousands except per share amounts)
Balances, March 31, 2018 $ 10,403  $ 541,004  $ (100) $ 805,993  $ —  $ 1,357,300 
Net income —  —  —  5,788  2,362  8,150 
Other comprehensive gain (net of tax of $11)
—  —  35  —  —  35 
Total comprehensive income
8,185 
Contributions —  102,958  —  —  197,042  300,000 
Transaction costs associated with sale of non-controlling interest
—  (2,254) —  —  —  (2,254)
Tax effect of the sale of non-controlling interest
—  (24,300) —  —  —  (24,300)
Activity in employee compensation plans (43,005 shares)
11  4,712  —  —  —  4,723 
Balances, June 30, 2018 $ 10,414  $ 622,120  $ (65) $ 811,781  $ 199,404  $ 1,643,654 

Six Months Ended June 30, 2018 
Shareholders' Equity Attributable to Unit Corporation
Common
Stock
Capital In Excess
of Par Value
Accumulated Other Comprehensive Income (Loss) Retained
Earnings
Non-controlling Interest in Consolidated 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 —  —  —  13,653  2,362  16,015 
Other comprehensive loss (net of tax of ($47))
—  —  (141) —  —  (141)
Total comprehensive income
15,874 
Contributions —  102,958  —  —  197,042  300,000 
Transaction costs associated with sale of non-controlling interest
—  (2,254) —  —  —  (2,254)
Tax effect of the sale of non-controlling interest
—  (24,300) —  —  —  (24,300)
Activity in employee compensation plans (1,209,232 shares)
134  9,901  —  —  —  10,035 
Balances, June 30, 2018 $ 10,414  $ 622,120  $ (65) $ 811,781  $ 199,404  $ 1,643,654 

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


8

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended
  June 30,
  2019  2018 
  (In thousands)
OPERATING ACTIVITIES:
Net income (loss) $ (10,299) $ 16,015 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization 128,418  115,439 
Amortization of debt issuance costs and debt discount (Note 6) 1,115  1,095 
(Gain) loss on derivatives (Note 10) (995) 21,223 
Cash proceeds (payments) on derivatives settled, net (Note 10) 5,314  (8,928)
Deferred tax (benefit) expense (2,318) 5,636 
(Gain) loss on disposition of assets 1,193  (322)
Stock compensation plans 11,187  12,073 
Contract assets and liabilities, net (Note 2) (1,283) (2,371)
Other, net 1,117  1,998 
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable 26,939  (1,865)
Accounts payable (30,374) (403)
Material and supplies (43)
Accrued liabilities (1,245) 1,572 
Other, net (1,225) (1,526)
Net cash provided by operating activities 127,501  159,640 
INVESTING ACTIVITIES:
Capital expenditures (246,638) (189,916)
Producing properties and other acquisitions (3,313) (962)
Proceeds from disposition of assets 7,340  23,528 
Net cash used in investing activities (242,611) (167,350)
FINANCING ACTIVITIES:
Borrowings under credit agreement 271,200  71,200 
Payments under credit agreement (160,200) (249,200)
Payments on finance leases (1,980) (1,901)
Proceeds from investments in non-controlling interest —  300,000 
Employee taxes paid by withholding shares (4,073) (4,947)
Transaction costs associated with sale of non-controlling interest —  (2,254)
Distributions to non-controlling interest (918) — 
Book overdrafts 5,298  (1,581)
Net cash provided by financing activities 109,327  111,317 
Net increase (decrease) in cash and cash equivalents (5,783) 103,607 
Cash and cash equivalents, beginning of period 6,452  701 
Cash and cash equivalents, end of period $ 669  $ 104,308 

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



9

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

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

The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
10

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 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 June 30, 2019 and December 31, 2018;
Statements of Operations for the three and six months ended June 30, 2019 and 2018;
Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2019 and 2018;
Statements of Changes in Shareholders' Equity for the three and six months ended June 30, 2019 and 2018; and
Statements of Cash Flows for the six months ended June 30, 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 six months ended June 30, 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 how we disaggregate our revenue and how we report our segment revenue (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 comes from contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas production and NGLs and selling those commodities. We sell the hydrocarbons (from our oil and natural gas and mid-stream segments) to other mid-stream and downstream oil and gas companies.

11

Oil and Natural Gas Revenues

Certain costs—as either a deduction from revenue or as an expense—are 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 have evaluated the mobilization and de-mobilization charges due under our outstanding drilling contracts. The impact of those charges to the financial statements was immaterial. As of June 30, 2019, we had 24 contract drilling contracts with terms ranging from one month to almost three years.

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

Mid-stream Contracts Revenues

Revenues are generated from fees earned for gas gathering and processing services provided to a customer. 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 six months ended June 30, 2019:

Contract Assets Amount
(In thousands)
Balance at December 31, 2018 (1)
$ 13,164 
Amounts invoiced in excess of revenue recognized (86)
Balance at June 30, 2019 (1)
$ 13,078 
_______________________
1.At December 31, 2018, total contract assets are included in prepaid expenses and other and other assets of $0.3 million and $12.9 million, respectively, in our Consolidated Balance Sheet. At June 30, 2019, total contract assets included prepaid expenses and other and other assets of $3.4 million and $9.7 million, respectively, in our Condensed Consolidated Balance Sheet.

Contract Liabilities Amount
(In thousands)
Balance at December 31, 2018 (1)
$ 9,882 
New contract 60 
Revenue included in beginning balance (1,429)
Balance at June 30, 2019 (1)
$ 8,513 

______________________
1.At December 31, 2018, total contract liabilities are included in current portion of other long-term liabilities and other long-term liabilities of $2.9 million and $7.0 million, respectively, in our Consolidated Balance Sheet. At June 30, 2019, total contract liabilities included current portion of other long-term liabilities and other long-term liabilities of $2.9 million and $5.6 million, respectively, in our Condensed Consolidated Balance Sheet.

Included below is the 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 July - December 2019 2020 2021  2022  2023 and Beyond  Total Remaining Impact to Revenue 
(In thousands) 
Demand fee contracts 3-9 years $ 1,295  $ (3,775) $ (3,501) $ 1,380  $ 36  $ (4,565)

12

NOTE 3 – DIVESTITURES

Oil and Natural Gas

We sold $2.1 million of non-core oil and natural gas assets, net of related expenses, during the first six months of 2019, compared to $22.4 million during the first six months of 2018. These proceeds 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 pre-tax non-cash write-down of approximately $147.9 million. During the first six months of 2019, we sold three of these drilling rigs and some of the other equipment to unaffiliated third parties. The proceeds of those sales, less costs to sell, was less than the applicable $3.0 million net book value resulting in a loss of $0.2 million. The remaining drilling rigs and equipment will be marketed for sale throughout 2019 and remain classified as assets held for sale. The net book value of those assets is $19.5 million.

NOTE 4 – EARNINGS (LOSS) PER SHARE

Information related to the calculation of earnings (loss) per share attributable to Unit Corporation is as follows:
Earnings (Loss)
(Numerator)
Weighted
Shares
(Denominator)
Per-Share
Amount
  (In thousands except per share amounts)
For the three months ended June 30, 2019
Basic loss attributable to Unit Corporation per common share $ (8,509) 52,930  $ (0.16)
Effect of dilutive stock options and restricted stock
—  —  — 
Diluted loss attributable to Unit Corporation per common share $ (8,509) 52,930  $ (0.16)
For the three months ended June 30, 2018
Basic earnings attributable to Unit Corporation per common share $ 5,788  52,050  $ 0.11 
Effect of dilutive stock options and restricted stock
—  731  — 
Diluted earnings attributable to Unit Corporation per common share $ 5,788  52,781  $ 0.11 

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

The following table shows the number of stock options (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
Three Months Ended
  June 30,
  2019  2018 
Stock options 42,000  66,500 
Average exercise price $ 48.56  $ 44.42 


13

Earnings (Loss) (Numerator) Weighted Shares (Denominator) Per-Share Amount
(In thousands except per share amounts)
For the six months ended June 30, 2019
Basic loss attributable to Unit Corporation per common share $ (12,013) 52,744  $ (0.23)
Effect of dilutive stock options and restricted stock —  —  — 
Diluted loss attributable to Unit Corporation per common share $ (12,013) 52,744  $ (0.23)
For the six months ended June 30, 2018
Basic earnings attributable to Unit Corporation per common share $ 13,653  51,891  $ 0.26 
Effect of dilutive stock options and restricted stock —  651  — 
Diluted earnings attributable to Unit Corporation per common share $ 13,653  52,542  $ 0.26 
Because of the net loss for the six months ended June 30, 2019, approximately 286,000 weighted average shares related to stock options and restricted stock were antidilutive and were excluded from the earnings per share calculation above.

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:
Six Months Ended
  June 30,
  2019  2018 
Stock options 42,000  66,500 
Average exercise price $ 48.56  $ 44.42 

NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of:
June 30,
2019
December 31,
2018
  (In thousands)
Employee costs $ 13,910  $ 22,056 
Lease operating expenses 10,552  12,756 
Interest payable 6,741  6,635 
Taxes 6,675  1,378 
Third-party credits 2,824  2,129 
Other 4,473  4,710 
Total accrued liabilities $ 45,175  $ 49,664 
14

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:
June 30,
2019
December 31,
2018
  (In thousands)
Unit credit agreement with an average interest rate of 4.2% at June 30, 2019 $ 103,500  $ — 
Superior credit agreement with an average interest rate of 6.5% at June 30, 2019 7,500  — 
6.625% senior subordinated notes due 2021 650,000  650,000 
Total principal amount 761,000  650,000 
Less: unamortized discount (1,303) (1,623)
Less: debt issuance costs, net (3,107) (3,902)
Total long-term debt $ 756,590  $ 644,475 

Unit Credit Agreement. Our Senior Credit Agreement (Unit credit agreement) 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 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, granting 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 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 or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty. At June 30, 2019, we had $103.5 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.

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The Unit credit agreement prohibits, among other things:

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

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 June 30, 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 June 30, 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 June 30, 2019, we had $7.5 million outstanding borrowings under the Superior credit agreement.

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

Superior's credit agreement is not guaranteed by Unit.

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

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

Unit, as the parent company, has no significant independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Effective April 3, 2018, Superior is no longer a Guarantor of the Notes. 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, unless the Company has exercised its right to redeem all of the Notes, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. As of May 15, 2019, we may redeem the Notes at a redemption price equal to 100% of the principal amount of the Notes plus accrued and unpaid interest on the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of June 30, 2019.

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

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
June 30,
2019
December 31,
2018
  (In thousands)
Asset retirement obligation (ARO) liability $ 67,433  $ 64,208 
Workers’ compensation 12,118  12,738 
Finance lease obligations 9,400  11,380 
Contract liability 8,513  9,881 
Separation benefit plans 9,749  8,814 
Deferred compensation plan 6,002  5,132 
Gas balancing liability 3,372  3,331 
116,587  115,484 
Less current portion 13,887  14,250 
Total other long-term liabilities $ 102,700  $ 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 July 1, 2019 (and through 2024) are $13.9 million, $697.5 million, $5.6 million, $10.7 million, and $105.8 million, respectively.

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All our AROs relate to the plugging costs associated with our oil and gas wells.
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The following table shows certain information about our estimated AROs for the periods indicated:
Six Months Ended
  June 30,
  2019  2018 
  (In thousands)
ARO liability, January 1: $ 64,208  $ 69,444 
Accretion of discount 1,168  1,248 
Liability incurred 3,656  211 
Liability settled (2,316) (3,142)
Liability sold (1,632) (94)
Revision of estimates (1)
2,349 

(4,829)
ARO liability, June 30: 67,433  62,838 
Less current portion 1,784  1,451 
Total long-term ARO $ 65,649  $ 61,387 
_______________________ 
1.Plugging liability estimates were revised in both 2019 and 2018 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS

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

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

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 is 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 Six Months Ended
June 30, June 30,
2019  2018  2019  2018 
(In millions)
Recognized stock compensation expense $ 4.7  $ 4.0  $ 8.5  $ 9.5 
Capitalized stock compensation cost for our oil and natural gas properties
0.7  0.6  1.3  1.0 
Tax benefit on stock-based compensation 1.2  1.0  2.1  2.3 
The remaining unrecognized compensation cost related to unvested awards at June 30, 2019 is approximately $24.8 million, of which $3.4 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is 0.8 of a year.

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

We did not grant any stock options during either of the three or six month periods ending June 30, 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
June 30, 2019 June 30, 2018
  Time
Vested
Performance Vested Time
Vested
Performance Vested
Shares granted:
Employees 1,500  —  5,000  — 
Non-employee directors 72,784  —  44,312  — 
74,284  —  49,312  — 
Estimated fair value (in millions):(1)
Employees $ —  $ —  $ 0.1  $ — 
Non-employee directors 0.9  —  0.9  — 
$ 0.9  $ —  $ 1.0  $ — 
Percentage of shares granted expected to be distributed:
Employees 95  % N/A    95  % N/A   
Non-employee directors 100%    N/A    100  % N/A   
_______________________
1.The performance shares represent 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)
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Six Months Ended Six Months Ended
June 30, 2019 June 30, 2018
  Time
Vested
Performance Vested Time
Vested
Performance Vested
Shares granted:
Employees 927,173  424,070  844,498  362,070 
Non-employee directors 72,784  —  44,312  — 
999,957  424,070  888,810  362,070 
Estimated fair value (in millions):(1)
Employees $ 14.6  $ 7.1  $ 16.2  $ 7.3 
Non-employee directors 0.9  —  0.9  — 
$ 15.5  $ 7.1  $ 17.1  $ 7.3 
Percentage of shares granted expected to be distributed:
Employees 95  % 54  % 95  % 74  %
Non-employee directors 100  % N/A    100  % N/A   
_______________________
1.The performance shares represent 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

The time vested restricted stock awards granted during the first six 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 cliff vests three years from the grant date based on the company's achievement of certain stock performance measures (TSR) at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second vests, 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 June 30, 2019, the participants are estimated to receive 7% of the 2019 and 63% of the 2018 performance-based shares. The CFTA performance measurement at June 30, 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 six months of 2019 was $4.0 million.

NOTE 10 – DERIVATIVES

Commodity Derivatives

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

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

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

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

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

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

At June 30, 2019, these derivatives were outstanding:
Term Commodity Contracted Volume Weighted Average 
Fixed Price
Contracted Market
Jul'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)
Jul'19 – Dec'19 Natural gas – basis swap 20,000 MMBtu/day $(0.659) PEPL
Jul'19 – Dec'19 Natural gas – basis swap 10,000 MMBtu/day $(0.625) NGL MIDCON
Jul'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
Jul'19 – Dec'19 Natural gas – collar 20,000 MMBtu/day $2.63 - $3.03 IF – NYMEX (HH)
Jul'19 – Dec'19 Crude oil – three-way collar 4,000 Bbl/day $61.25 - $51.25 - $72.93 WTI – NYMEX

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 June 30,
2019
December 31,
2018
    (In thousands)
Commodity derivatives:
Current Current derivative asset $ 8,513  $ 12,870 
Long-term Non-current derivative asset —  — 
Total derivative assets $ 8,513  $ 12,870 

    Derivative Liabilities
    Fair Value
  Balance Sheet Location June 30,
2019
December 31,
2018
    (In thousands)
Commodity derivatives:
Current Current derivative liability $ —  $ — 
Long-term Non-current derivative liability 256  293 
Total derivative liabilities $ 256  $ 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.

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Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations at June 30:
Three Months Ended Six Months Ended
June 30, June 30,
2019  2018  2019  2018 
  (In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $2,658, ($6,855), $5,314 and ($8,928), respectively $ 7,927  $ (14,461) $ 995  $ (21,223)
$ 7,927  $ (14,461) $ 995  $ (21,223)

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, 2019 $ 830  $ —  $ 645  $ 185 
December 31, 2018 $ 830  $ —  $ 636  $ 194 

During the second quarter of 2017, we received available-for-sale securities in payment of 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 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.

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The following tables set forth our recurring fair value measurements:
  June 30, 2019
  Level 1 Level 2 Level 3 Effect
of Netting
Net Amounts Presented
  (In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets $ —  $ 5,422  $ 3,945  $ (854) $ 8,513 
Liabilities —  (1,110) —  854  (256)
Total commodity derivatives —  4,312  3,945  —  8,257 
Equity securities 185  —  —  —  185 
$ 185  $ 4,312  $ 3,945  $ —  $ 8,442 

  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 June 30, 2019.

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

Level 1 Fair Value Measurements

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

Level 2 Fair Value Measurements

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

Level 3 Fair Value Measurements

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

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The following table is a reconciliation of our level 3 fair value measurements: 
  Net Derivatives
Three Months Ended Six Months Ended
June 30, June 30,
  2019 2018 2019 2018
  (In thousands)
Beginning of period $ 3,080  $ (3,206) $ 10,630  $ (206)
Total gains or losses (realized and unrealized):
Included in earnings (1)
2,060  (4,704) (3,374) (8,624)
Settlements (1,195) 1,775  (3,311) 2,695 
End of period $ 3,945  $ (6,135) $ 3,945  $ (6,135)
Total earnings (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period
$ 865  $ (2,929) $ (6,685) $ (5,929)
_______________________
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, 2019:
Commodity (1)
Fair Value Valuation Technique Unobservable Input Range
  (In thousands)      
Oil three-way collars $ 2,828  Discounted cash flow Forward commodity price curve $0 - $9.00
Natural gas collars $ 1,117  Discounted cash flow Forward commodity price curve $0 - $0.48
 _______________________
1.The commodity contracts detailed in this category include non-exchange-traded crude oil three-way collars and natural gas collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

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

Based on the borrowing rates available to us for credit agreement debt with similar terms and maturities and considering the risk of our non-performance, long-term debt under the Unit and Superior credit agreements approximate its fair value and at June 30, 2019 we had $103.5 million of outstanding borrowings under the Unit and $7.5 million under the Superior credit agreements. We had no borrowing under either the Unit or Superior Credit 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 June 30, 2019 and December 31, 2018 were $645.6 million and $644.5 million, respectively. We estimate the fair value of the Notes using quoted marked prices at June 30, 2019 and December 31, 2018 was $592.4 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
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calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the company’s AROs is presented in Note 7 – Asset Retirement Obligations.

NOTE 12 – LEASES

Operating Leases under ASC 840

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

Operating Leases under ASC 842

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

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

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

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

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

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

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

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

The following table shows supplemental cash flow information related to leases for the six months of June 30, 2019:
Amount
(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases $ 1,616 
Financing cash flows for finance leases 1,980 
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 June 30, 2019:
Classification on the Consolidated Balance Sheet June 30,
2019
(In thousands)
Assets
Operating right of use assets Right of use assets $ 8,302 
Finance right of use assets Property, plant, and equipment, net 18,416 
Total right of use assets $ 26,718 
Liabilities
Current liabilities:
Operating lease liabilities Current operating lease liabilities $ 4,519 
Finance lease liabilities Current portion of other long-term liabilities 4,081 
Non-current liabilities:
Operating lease liabilities Operating lease liabilities 3,556 
Finance lease liabilities Other long-term liabilities 5,319 
Total lease liabilities $ 17,475 

The following table shows certain information related to the lease costs for our finance and operating leases for the three and six months ended June 30, 2019:
Three Months Ended Six Months Ended
June 30,  June 30,
2019 2019
(In thousands)
Components of total lease cost:
Amortization of finance leased assets $ 995  $ 1,980 
Interest on finance lease liabilities 100  211 
Operating lease cost 1,052  1,651