Company Quick10K Filing
Quick10K
Unit
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$17.27 54 $934
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
8-K 2019-02-21 Earnings, Exhibits
8-K 2018-11-06 Earnings, Exhibits
8-K 2018-10-18 Enter Agreement
8-K 2018-08-09 Earnings, Exhibits
8-K 2018-08-01 Amendment
8-K 2018-05-10 Enter Agreement, Exhibits
8-K 2018-04-02 Enter Agreement, M&A, Other Events, Exhibits
8-K 2018-03-28 Enter Agreement, Regulation FD, Exhibits
8-K 2018-03-14 Other Events, Exhibits
8-K 2018-03-07 Enter Agreement, Exhibits
8-K 2018-02-22 Earnings, Exhibits
DVN Devon Energy
PDCE PDC Energy
WRD Wildhorse Resource Development
BCEI Bonanza Creek Energy
ESTE Earthstone Energy
PNRG Primeenergy
EPM Evolution Petroleum
UPL Ultra Petroleum
CRT Cross Timbers Royalty Trust
SNDE Sundance Energy Australia
UNT 2018-09-30
Part I. Financial Information
Item 1. Financial Statements
Note 1 - Basis of Preparation and Presentation
Note 2 - Revenue From Contracts with Customers
Note 3 - Divestitures
Note 4 - Earnings per Share
Note 5 - Accrued Liabilities
Note 6 - Long-Term Debt and Other Long-Term Liabilities
Note 7 - Asset Retirement Obligations
Note 8 - New Accounting Pronouncements
Note 9 - Stock-Based Compensation
Note 10 - Derivatives
Note 11 - Fair Value Measurements
Note 12 - Commitments and Contingencies
Note 13 - Variable Interest Entity Arrangements
Note 14 - Equity
Note 15 - Industry Segment Information
Note 16 - Supplemental Condensed Consolidating Financial Information
Note 17 - Subsequent Event
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosure About Market Risk
Item 4. Controls and Procedures
Part II. Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
EX-10.1 exhibit101fifthamendmentto.htm
EX-31.1 unt-20180930xex311.htm
EX-31.2 unt-20180930xex312.htm
EX-32 unt-20180930xex32.htm

Unit Earnings 2018-09-30

UNT 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 unt-2018930x10q.htm 10-Q Document

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 September 30, 2018
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]
image2a01a13.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 October 19, 2018, 54,058,016 shares of the issuer's common stock were outstanding.



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

1


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;
our intended use of the proceeds from the sale of 50% of the interest we owned in our mid-stream segment; and
our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods.
These statements are based on assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and expected future developments, and other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to several risks and uncertainties, any one or combination of which could cause our actual results to differ materially from our expectations and predictions, including:
the risk factors discussed in this document and in the documents (if any) we incorporate by reference;
general economic, market, or business conditions;
the availability of and nature of (or lack of) business opportunities we pursue;
demand for our land drilling services;
changes in laws or regulations;
changes in the current geopolitical situation;
risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
risks associated with future weather conditions;
decreases or increases in commodity prices;
putative class action lawsuits that may cause substantial expenditures and divert management's attention; and
other factors, most of which are beyond our control.

2


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.

3


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
 
September 30,
2018
 
December 31,
2017
 
 
(In thousands except share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
91,557

 
$
701

Accounts receivable, net of allowance for doubtful accounts of $2,450 at both September 30, 2018 and December 31, 2017, respectively
 
122,123

 
111,512

Materials and supplies
 
505

 
505

Current derivative asset (Note 10)
 

 
721

Prepaid expenses and other
 
9,419

 
6,233

Total current assets
 
223,604

 
119,672

Property and equipment:
 
 
 
 
Oil and natural gas properties on the full cost method:
 
 
 
 
Proved properties
 
5,901,661

 
5,712,813

Unproved properties not being amortized
 
332,886

 
296,764

Drilling equipment
 
1,632,540

 
1,593,611

Gas gathering and processing equipment
 
751,715

 
726,236

Saltwater disposal systems
 
67,074

 
62,618

Corporate land and building
 
59,081

 
59,080

Transportation equipment
 
29,103

 
29,631

Other
 
56,750

 
53,439

 
 
8,830,810

 
8,534,192

Less accumulated depreciation, depletion, amortization, and impairment
 
6,325,160

 
6,151,450

Net property and equipment
 
2,505,650

 
2,382,742

Goodwill
 
62,808

 
62,808

Other assets
 
28,703

 
16,230

Total assets (1)
 
$
2,820,765

 
$
2,581,452


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

4


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

 
 
September 30,
2018
 
December 31,
2017
 
 
(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
143,552

 
$
112,648

Accrued liabilities (Note 5)
 
67,743

 
48,523

Income taxes payable
 
1,051

 

Current derivative liability (Note 10)
 
13,067

 
7,763

Current portion of other long-term liabilities (Note 6)
 
14,150

 
13,002

Total current liabilities
 
239,563

 
181,936

Long-term debt less debt issuance costs (Note 6)
 
643,921

 
820,276

Non-current derivative liability (Note 10)
 
1,542

 

Other long-term liabilities (Note 6)
 
101,410

 
100,203

Deferred income taxes
 
164,964

 
133,477

Commitments and contingencies (Note 12)
 

 

Shareholders’ equity:
 
 
 
 
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued
 

 

Common stock, $.20 par value, 175,000,000 shares authorized, 54,063,705 and 52,880,134 shares issued as of September 30, 2018 and December 31, 2017, respectively
 
10,414

 
10,280

Capital in excess of par value
 
626,746

 
535,815

Accumulated other comprehensive income (loss) (Note 14)
 
(103
)
 
63

Retained earnings
 
830,680

 
799,402

Total shareholders’ equity attributable to Unit Corporation
 
1,467,737

 
1,345,560

Non-controlling interests in consolidated subsidiaries
 
201,628

 

Total shareholders' equity
 
1,669,365

 
1,345,560

Total liabilities(1) and shareholders’ equity
 
$
2,820,765

 
$
2,581,452

_______________________
(1)
Unit Corporation's consolidated total assets as of September 30, 2018 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $41.8 million and $416.7 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of September 30, 2018 include total current and long-term liabilities of the VIE of $38.6 million and $16.1 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 13 – Variable Interest Entity Arrangements.


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


5


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED INCOME STATEMENTS (UNAUDITED)
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In thousands except per share amounts)
Revenues:
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
111,623

 
$
85,470

 
$
317,040

 
$
256,241

Contract drilling
 
50,612

 
51,619

 
143,527

 
128,059

Gas gathering and processing
 
57,823

 
51,399

 
167,926

 
150,493

Total revenues
 
220,058

 
188,488

 
628,493

 
534,793

Expenses:
 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
 
Oil and natural gas
 
32,139

 
33,911

 
100,519

 
95,873

Contract drilling
 
32,032

 
34,747

 
95,593

 
91,213

Gas gathering and processing
 
43,134

 
38,116

 
124,441

 
111,862

Total operating costs
 
107,305

 
106,774

 
320,553

 
298,948

Depreciation, depletion, and amortization
 
63,537

 
54,533

 
178,976

 
151,545

General and administrative
 
9,278

 
9,235

 
28,752

 
26,902

Gain on disposition of assets
 
(253
)
 
(81
)
 
(575
)
 
(1,153
)
Total operating expenses
 
179,867

 
170,461

 
527,706

 
476,242

Income from operations
 
40,191

 
18,027

 
100,787

 
58,551

Other income (expense):
 
 
 
 
 
 
 
 
Interest, net
 
(7,945
)
 
(9,944
)
 
(25,678
)
 
(28,807
)
Gain (loss) on derivatives
 
(4,385
)
 
(2,614
)
 
(25,608
)
 
21,019

Other, net
 
6

 
5

 
17

 
14

Total other income (expense)
 
(12,324
)
 
(12,553
)
 
(51,269
)
 
(7,774
)
Income before income taxes
 
27,867

 
5,474

 
49,518

 
50,777

Income tax expense:
 
 
 
 
 
 
 
 
Deferred
 
6,744

 
1,769

 
12,380

 
22,084

Total income taxes
 
6,744

 
1,769

 
12,380

 
22,084

Net income
 
21,123

 
3,705

 
37,138

 
28,693

Net income attributable to non-controlling interest
 
2,224

 

 
4,586

 

Net income attributable to Unit Corporation
 
18,899

 
3,705

 
32,552

 
28,693

Net income attributable to Unit Corporation per common share:
 
 
 
 
 
 
 
 
Basic
 
$
0.36

 
$
0.07

 
$
0.63

 
$
0.56

Diluted
 
$
0.36

 
$
0.07

 
$
0.62

 
$
0.56


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


6


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Net income
$
21,123

 
$
3,705

 
$
37,138

 
$
28,693

Other comprehensive income (loss), net of taxes:
 
 
 
 
 
 
 
Unrealized gain (loss) on securities, net of tax of ($13), $20, ($60) and $32
(38
)
 
33

 
(179
)
 
53

Comprehensive income
21,085

 
3,738

 
36,959

 
28,746

Less: Comprehensive income attributable to non-controlling interest
2,224

 

 
4,586

 

Comprehensive income attributable to Unit Corporation
$
18,861

 
$
3,738

 
$
32,373

 
$
28,746


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


7


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
 
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 (Notes 1 and 2)

 

 
13

 
(1,274
)
 

 
(1,261
)
Net income

 

 

 
32,552

 
4,586

 
37,138

Other comprehensive loss (net of tax of ($60))

 

 
(179
)
 

 

 
(179
)
Total comprehensive income
 
 
 
 
 
 
 
 
 
 
36,959

Contributions

 
102,958

 

 

 
197,042

 
300,000

Transaction costs associated with sale of non-controlling interest

 
(2,303
)
 

 

 

 
(2,303
)
Tax effect of the sale of non-controlling interest

 
(24,300
)
 

 

 

 
(24,300
)
Activity in employee compensation plans (1,183,571 shares)
134

 
14,576

 

 

 

 
14,710

Balances, September 30, 2018
$
10,414

 
$
626,746

 
$
(103
)
 
$
830,680

 
$
201,628

 
$
1,669,365


 
Shareholders' Equity Attributable to Unit Corporation
 
 
 
 
 
Common
Stock
 
Capital In Excess
of Par Value
 
Accumulated Other Comprehensive Income
 
Retained
Earnings
 
Non-controlling Interest in Consolidated Subsidiaries
 
Total
 
(In thousands except per share amounts)
Balances, December 31, 2016
$
10,016

 
$
502,500

 
$

 
$
681,554

 
$

 
$
1,194,070

Net income

 

 

 
28,693

 

 
28,693

Other comprehensive income (net of tax of $32)

 

 
53

 

 

 
53

Total comprehensive income
 
 
 
 
 
 
 
 
 
 
28,746

Activity in employee compensation plans (1,385,342 shares)
261

 
28,828

 

 

 

 
29,089

Balances, September 30, 2017
$
10,277

 
$
531,328

 
$
53

 
$
710,247

 
$

 
$
1,251,905


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



8


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
Nine Months Ended
 
 
September 30,
 
 
2018
 
2017
 
 
(In thousands)
OPERATING ACTIVITIES:
 
 
 
 
Net income
 
$
37,138

 
$
28,693

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, and amortization
 
178,976

 
151,545

Amortization of debt issuance costs and debt discount (Note 6)
 
1,645

 
1,616

(Gain) loss on derivatives (Note 10)
 
25,608

 
(21,019
)
Cash payments on derivatives settled, net (Note 10)
 
(18,040
)
 
(729
)
Deferred tax expense
 
12,380

 
22,084

Gain on disposition of assets
 
(575
)
 
(1,153
)
Stock compensation plans
 
17,397

 
12,478

Contract assets and liabilities, net (Note 2)
 
(3,671
)
 

Other, net
 
2,835

 
1,397

Changes in operating assets and liabilities increasing (decreasing) cash:
 
 
 
 
Accounts receivable
 
(15,558
)
 
(36,381
)
Accounts payable
 
(14,867
)
 
4,873

Material and supplies
 

 
17

Income taxes
 

 
(15
)
Accrued liabilities
 
16,242

 
20,280

Other, net
 
(2,975
)
 
1,106

Net cash provided by operating activities
 
236,535

 
184,792

INVESTING ACTIVITIES:
 
 
 
 
Capital expenditures
 
(304,054
)
 
(167,392
)
Producing properties and other acquisitions
 
(769
)
 
(55,429
)
Proceeds from disposition of assets
 
25,316

 
20,137

Other
 

 
(1,500
)
Net cash used in investing activities
 
(279,507
)
 
(204,184
)
FINANCING ACTIVITIES:
 
 
 
 
Borrowings under credit agreement
 
71,200

 
251,401

Payments under credit agreement
 
(249,200
)
 
(250,100
)
Payments on capitalized leases
 
(2,869
)
 
(2,967
)
Proceeds from common stock issued, net of issue costs (Note 14)
 

 
18,623

Proceeds from investments of non-controlling interest
 
300,000

 

Transaction costs associated with sale of non-controlling interest
 
(2,303
)
 

Book overdrafts
 
17,000

 
2,364

Net cash provided by financing activities
 
133,828

 
19,321

Net increase (decrease) in cash and cash equivalents
 
90,856

 
(71
)
Cash and cash equivalents, beginning of period
 
701

 
893

Cash and cash equivalents, end of period
 
$
91,557

 
$
822


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

 
 
Nine Months Ended
 
 
September 30,
 
 
2018
 
2017
 
 
(In thousands)
Supplemental disclosure of cash flow information:
 
 
 
 
Cash paid during the year for:
 
 
 
 
Interest paid (net of capitalized)
 
14,418

 
14,601

Income taxes
 
3,600

 

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
 
(28,770
)
 
(20,122
)
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations
 
8,546

 
(3,203
)

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

10


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 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 13 – Variable Interest Entity Arrangements.

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

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

Balance Sheets at September 30, 2018 and December 31, 2017;
Income Statements for the three and nine months ended September 30, 2018 and 2017;
Statements of Comprehensive Income for the three and nine months ended September 30, 2018 and 2017;
Statements of Changes in Shareholders' Equity for the nine months ended September 30, 2018 and 2017; and
Statements of Cash Flows for the nine months ended September 30, 2018 and 2017.

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 nine months ended September 30, 2018 and 2017 are not necessarily indicative of the results we may realize for the full year of 2018, or that we realized for the full year of 2017.

Accounting Changes - Recent Accounting Pronouncements - Adopted

As of January 1, 2018, we adopted ASU 2018-02 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This standard is explained further in Note 8 - New Accounting Pronouncements. We adopted this amendment early and it had no material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and we now use 24.5%. This change is reflected in our Unaudited Condensed Consolidated Statements of Comprehensive Income and in Note 14 - Equity.

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

The additional disclosures required by the ASU are included in Note 2 – Revenue from Contracts with Customers.

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 15 – Industry Segment Information). Revenue from the oil and natural gas segment is derived from sales of our oil and natural gas production. Revenue from the contract drilling segment is derived by contracting with upstream companies to drill an agreed-on number of wells or provide

11


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.

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

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

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

Certain costs—as either a deduction from revenue or as an expense—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. The impact of the adoption of ASC 606 did not impact income from operations or net income for the three or nine months ended September 30, 2018. These tables summarize the impact of the adoption of ASC 606 on revenue and operating costs for the three and nine months ended September 30, 2018, respectively:
 
 
Three Months Ended September 30, 2018
 
 
As Reported
 
Adjustments due to ASC 606
 
Amounts without the Adoption of ASC 606
 
 
(In thousands)
Oil and natural gas revenues
 
$
111,623

 
$
(5,200
)
 
$
116,823

Oil and natural gas operating costs
 
32,139

 
(5,200
)
 
37,339

Gross profit
 
$
79,484

 
$

 
$
79,484

 
 
Nine Months Ended September 30, 2018
 
 
As Reported
 
Adjustments due to ASC 606
 
Amounts without the Adoption of ASC 606
 
 
(In thousands)
Oil and natural gas revenues
 
$
317,040

 
$
(12,102
)
 
$
329,142

Oil and natural gas operating costs
 
100,519

 
(12,102
)
 
112,621

Gross profit
 
$
216,521

 
$

 
$
216,521


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

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

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

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

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

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

All consideration received for contract drilling is variable, excluding termination fees, which we have concluded will not apply to our contracts as of the reporting date. The consideration is calculated by multiplying a variable quantity (number of days/hours) by an agreed-on daily price (for the daily rate, mobilization and demobilization revenue). Other revenue items under the contract may include bonus/penalty revenue, reimbursable revenue, drilling fluid rates, and early termination fees. All variable consideration is not constrained but is settled at the end of the month; therefore, whether the variability is constrained or not does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period excluding certain bonuses/penalties which might be based on activity that occurs over the entire term of the contract. We have evaluated the mobilization and de-mobilization charges on outstanding contracts, however, the impact to the financial statements was immaterial. As of September 30, 2018, we had 34 contract drilling contracts (21 of which are long-term) for a duration of two months to almost three years.


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Under the guidance in relation to disclosures regarding the remaining performance obligations, there is a practical expedient for contracts with an original expected duration of one year or less (ASC 606-10-50-14) and for contracts where the entity can recognize revenue as invoiced (ASC 606-10-55-18). The majority 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, and Implementation impact to retained earnings, and Performance Obligations

Revenues are generated from the fees earned for gas gathering and processing services provided to a customer. The typical revenue contracts used by this segment are gas gathering and processing agreements. Contract terms range from a single month to terms spanning a decade or more, some include evergreen provisions. Fees for mid-stream services (gathering, transportation, processing) are performance obligations and meet the criteria of over time recognition which could be considered a series of distinct performance obligations that represents one overall performance obligation of gas gathering and processing services.

On adoption of the standard, an adjustment to opening retained earnings was made for $1.7 million ($1.3 million, net of tax). This adjustment—related to the timing of revenue recognized on certain demand fees—impacted our Unaudited Condensed Consolidated Balance Sheet (for the periods indicated) as follows:
 
 
Balance at December 31, 2017
 
Adjustments due to ASC 606
 
Balance at January 1,
 2018
 
 
(In thousands)
Assets:
 
 
 
 
 
 
Other assets
 
$
16,230

 
$
10,798

 
$
27,028

Liabilities and shareholders' equity:
 
 
 
 
 
 
Current portion of other long-term liabilities
 
13,002

 
2,748

 
15,750

Other long-term liabilities
 
100,203

 
9,737

 
109,940

Deferred income taxes
 
133,477

 
(413
)
 
133,064

Retained earnings
 
799,402

 
(1,274
)
 
798,128


At September 30, 2018:
 
 
As Reported
 
Adjustments due to ASC 606
 
Amounts without the Adoption of ASC 606
 
 
(In thousands)
Assets:
 
 
 
 
 
 
Prepaid expenses and other
 
$
9,419

 
$
206

 
$
9,213

Other assets
 
28,703

 
12,383

 
16,320

Liabilities and shareholders' equity:
 
 
 
 
 
 
Current portion of other long-term liabilities
 
14,150

 
2,874

 
11,276

Other long-term liabilities
 
101,410

 
7,731

 
93,679

Deferred income taxes
 
164,964

 
486

 
164,478

Retained earnings
 
830,680

 
1,498

 
829,182



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For the three months ended September 30, 2018:
 
 
As Reported
 
Adjustments due to ASC 606
 
Amounts without the Adoption of ASC 606
 
 
(In thousands)
Gas gathering and processing revenues
 
$
57,823

 
$
1,300

 
$
56,523

Deferred income tax expense
 
6,744

 
318

 
6,426

Net income
 
21,123

 
982

 
20,141


This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the Unaudited Condensed Consolidated Income Statement for the nine months ended September 30, 2018:
 
 
As Reported
 
Adjustments due to ASC 606
 
Amounts without the Adoption of ASC 606
 
 
(In thousands)
Gas gathering and processing revenues
 
$
167,926

 
$
3,671

 
$
164,255

Deferred income tax expense
 
12,380

 
899

 
11,481

Net income
 
37,138

 
2,772

 
34,366


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

Included below is the additional fixed revenue we will earn over the remaining term of the contracts and excludes all variable consideration to be earned with the associated contract.
Contract
Remaining Term of Contract
October - December 2018
2019
2020
2021
2022
Total Remaining Impact to Revenue
 
 
(In thousands)
 
Demand fee contracts
4-5 years
$
1,299

$
2,632

$
(3,781
)
$
(3,507
)
$
1,374

$
(1,983
)

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

 
$
10,798

 
$
1,791

Contract liabilities
 
10,605

 
12,485

 
(1,880
)
Contract assets (liabilities), net
 
$
1,984

 
$
(1,687
)
 
$
3,671


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

15


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

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

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

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

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

NOTE 3 – DIVESTITURES
    
Divestitures

Oil and Natural Gas

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

Mid-Stream

On April 3, 2018, we sold 50% of the ownership interest in our mid-stream segment, Superior. The purchaser is 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. We received $300.0 million because of this sale. A portion of the proceeds were used to pay down our bank debt and the remainder will accelerate the drilling program of our upstream subsidiary, Unit Petroleum Company, make additional capital investments in the jointly owned Superior, and for general working capital purposes. In connection with the sale of the interest in Superior, we took the necessary actions under the Indenture governing our outstanding senior subordinated notes to secure the ability to close the sale and have Superior released from the Indenture.

Superior will be governed and managed under its Amended and Restated Limited Liability Company Agreement and the Master Services and Operating Agreement (MSA) signed by Superior and an affiliate of Unit, as both agreements may be amended occasionally. Further details are in Note 13 – Variable Interest Entity Arrangements.


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NOTE 4 – EARNINGS PER SHARE

Information related to the calculation of earnings per share attributable to Unit Corporation follows:
 
 
Earnings
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
 
(In thousands except per share amounts)
For the three months ended September 30, 2018
 
 
 
 
 
 
Basic earnings attributable to Unit Corporation per common share
 
$
18,899

 
52,068

 
$
0.36

Effect of dilutive stock options and restricted stock
 

 
1,072

 

Diluted earnings attributable to Unit Corporation per common share
 
$
18,899

 
53,140

 
$
0.36

For the three months ended September 30, 2017
 
 
 
 
 
 
Basic earnings attributable to Unit Corporation per common share
 
$
3,705

 
51,386

 
$
0.07

Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)
 

 
586

 

Diluted earnings attributable to Unit Corporation per common share
 
$
3,705

 
51,972

 
$
0.07


The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
 
 
Three Months Ended
 
 
September 30,
 
 
2018
 
2017
Stock options and SARs
 
66,500

 
178,755

Average exercise price
 
$
44.42

 
$
47.75


 
 
Earnings (Loss)
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
 
(In thousands except per share amounts)
For the nine months ended September 30, 2018
 
 
 
 
 
 
Basic earnings attributable to Unit Corporation per common share
 
$
32,552

 
51,951

 
$
0.63

Effect of dilutive stock options and restricted stock
 

 
808

 
(0.01
)
Diluted earnings attributable to Unit Corporation per common share
 
$
32,552

 
52,759

 
$
0.62

For the nine months ended September 30, 2017
 
 
 
 
 
 
Basic earnings attributable to Unit Corporation per common share
 
$
28,693

 
51,019

 
$
0.56

Effect of dilutive stock options, restricted stock, and SARs
 

 
550

 

Diluted earnings attributable to Unit Corporation per common share
 
$
28,693

 
51,569

 
$
0.56


The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
 
 
Nine Months Ended
 
 
September 30,
 
 
2018
 
2017
Stock options and SARs
 
66,500

 
178,755

Average exercise price
 
$
44.42

 
$
47.75



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NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of:
 
 
September 30,
2018
 
December 31,
2017
 
 
(In thousands)
Employee costs
 
$
17,880

 
$
19,521

Interest payable
 
17,446

 
6,745

Lease operating expenses
 
11,474

 
11,819

Taxes
 
10,317

 
3,404

Derivative settlements
 
3,383

 

Third-party credits
 
2,099

 
2,240

Other
 
5,144

 
4,794

Total accrued liabilities
 
$
67,743

 
$
48,523

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

Long-Term Debt

Our long-term debt as of the dates indicated consisted of the following:
 
 
September 30,
2018
 
December 31,
2017
 
 
(In thousands)
Unit credit agreement with an average interest rate of 3.4% at December 31, 2017
 
$

 
$
178,000

Superior credit agreement
 

 

6.625% senior subordinated notes due 2021
 
650,000

 
650,000

Total principal amount
 
650,000

 
828,000

Less: unamortized discount
 
(1,780
)
 
(2,234
)
Less: debt issuance costs, net
 
(4,299
)
 
(5,490
)
Total long-term debt
 
$
643,921

 
$
820,276


Unit Credit Agreement. On October 18, 2018, we signed a Fifth Amendment to our Senior Credit Agreement (Unit credit agreement) originally scheduled to mature on April 10, 2020. The details of this amendment are discussed in Note 17 – Subsequent Events and have not been incorporated into the discussion of the Unit credit agreement immediately below.

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

On May 2, 2018, the company signed 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.

We are charged a commitment fee of 0.50% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the total borrowing base. We paid $1.0 million in previous origination, agency, syndication, and other related fees. We incurred no additional fees related to the fourth amendment. We are amortizing these fees over the life of the Unit credit agreement. Under the Unit credit agreement, we have pledged as collateral 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties.


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

At our election, any part of the outstanding debt under the Unit credit agreement can be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base for the term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the Unit credit agreement but in no event less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At September 30, 2018, we had no outstanding borrowings under the Unit credit agreement.

We can use borrowings for financing general working capital requirements for (a) exploration, development, production, and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets 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.

Effective September 30, 2018, 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 September 30, 2018, we were in compliance with the Unit credit agreement 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.

Superior is 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 Superior credit agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As of September 30, 2018, Superior was in compliance with the Superior credit agreement 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.

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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 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. 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 September 30, 2018.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
 
 
September 30,
2018
 
December 31,
2017
 
 
(In thousands)
Asset retirement obligation (ARO) liability
 
$
62,727

 
$
69,444

Workers’ compensation
 
12,832

 
13,340

Capital lease obligations
 
12,355

 
15,224

Contract liability
 
10,605

 

Separation benefit plans
 
8,135

 
6,524

Deferred compensation plan
 
5,623

 
5,390

Gas balancing liability
 
3,283

 
3,283

 
 
115,560

 
113,205

Less current portion
 
14,150

 
13,002

Total other long-term liabilities
 
$
101,410

 
$
100,203


Estimated annual principal payments under the terms of our long-term debt and other long-term liabilities during the five successive twelve-month periods beginning October 1, 2018 (and through 2023) are $14.1 million, $43.1 million, $659.8 million, $4.6 million, and $2.3 million, respectively.


20


Capital Leases

In 2014, Superior entered into capital lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $4.0 million current portion of the capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $8.4 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 2018. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $4.6 million and $0.8 million, respectively, at September 30, 2018. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, Superior has the option to purchase the assets at 10% of their then fair market value.

Future payments required under the capital leases at September 30, 2018 are:
 
 
Amount
Beginning October 1,
 
(In thousands)
2018
 
$
6,195

2019
 
6,195

2020
 
5,322

Total future payments
 
17,712

Less payments related to:
 
 
Maintenance
 
4,601

Interest
 
756

Present value of future minimum payments
 
$
12,355


NOTE 7 – ASSET RETIREMENT OBLIGATIONS

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

The following table shows certain information about our AROs for the periods indicated:
 
 
Nine Months Ended
 
 
September 30,
 
 
2018
 
2017
 
 
(In thousands)
ARO liability, January 1:
 
$
69,444

 
$
70,170

Accretion of discount
 
1,829

 
2,112

Liability incurred
 
244

 
1,123

Liability settled
 
(3,907
)
 
(1,350
)
Liability sold
 
(105
)
 
(1,563
)
Revision of estimates (1)
 
(4,778
)

4,993

ARO liability, September 30:
 
62,727

 
75,485

Less current portion
 
1,451

 
2,947

Total long-term ARO
 
$
61,276

 
$
72,538

_______________________ 
(1)
Plugging liability estimates were revised in both 2018 and 2017 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

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

21


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

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

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

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

Leases. The FASB has issued several accounting standards updates and amendments related to leases in the past two years, which are codified within Topic 842. For public companies, these are effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard requires lessees to recognize at the commencement date of a lease a lease liability, which represents the lessee's obligation to make lease payments arising from the lease, measured on a discounted basis; and a right-of-use asset, which represents the lessee's right to use a specified asset for the lease term. Other recently issued amendments to Topic 842 have provided clarifying guidance regarding land easements, an additional modified retrospective transition method, and added several practical expedients to apply Topic 842 for both lessees and lessors. The standard will not apply to leases of mineral rights.

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

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

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

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

Adopted Standards

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

22


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

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

The additional disclosures required by ASC 606 have been included in Note 2 – Revenue from Contracts with Customers.

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

NOTE 9 – STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In millions)
Recognized stock compensation expense
 
$
4.1

 
$
3.2

 
$
13.6

 
$
9.0

Capitalized stock compensation cost for our oil and natural gas properties
 
0.6

 
0.5

 
1.6

 
1.3

Tax benefit on stock-based compensation
 
1.0

 
1.2

 
3.3

 
3.4


The remaining unrecognized compensation cost related to unvested awards at September 30, 2018 is approximately $19.0 million, of which $2.4 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."


23


We granted no SARs or stock options during either of the three or nine month periods ending September 30, 2018 or 2017. We did not grant any restricted stock awards during either of the three month periods ending September 30, 2018 or 2017. This table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated:
 
 
Nine Months Ended
 
Nine Months Ended
 
 
September 30, 2018
 
September 30, 2017
 
 
Time
Vested
 
Performance Vested
 
Time
Vested
 
Performance Vested
Shares granted:
 
 
 
 
 
 
 
 
Employees
 
844,498

 
362,070

 
475,799

 
173,373

Non-employee directors
 
44,312

 

 
49,104

 

 
 
888,810

 
362,070

 
524,903

 
173,373

Estimated fair value (in millions):(1)
 
 
 
 
 
 
 
 
Employees
 
$
16.2

 
$
7.3

 
$
11.8

 
$
4.5

Non-employee directors
 
0.9

 

 
0.9

 

 
 
$
17.1

 
$
7.3

 
$
12.7

 
$
4.5

Percentage of shares granted expected to be distributed:
 
 
 
 
 
 
 
 
Employees
 
95
%
 
74
%
 
95
%
 
91
%
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 nine months of 2018 and 2017 are being recognized over a three-year vesting period. During the first quarter of 2018 and 2017, 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 September 30, 2018, the participants are estimated to receive 49% of the 2018, 92% of the 2017, and 170% of the 2016 performance-based shares. The CFTA performance measurement at September 30, 2018 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 2018 awards for the first nine months of 2018 was $7.5 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 September 30, 2018, 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.


24


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 September 30, 2018, these derivatives were outstanding:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Oct'18
 
Natural gas – swap
 
30,000 MMBtu/day
 
$3.005
 
IF – NYMEX (HH)
Nov’18 – Dec'18
 
Natural gas – swap
 
20,000 MMBtu/day
 
$3.013
 
IF – NYMEX (HH)
Jan'19 – Dec'19
 
Natural gas – swap
 
10,000 MMBtu/day
 
$2.810
 
IF – NYMEX (HH)
Oct'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.190)
 
NGPL TEXOK
Oct'18 – Dec'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.678)
 
PEPL
Oct'18 – Dec'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.568)
 
NGPL MIDCON
Nov’18 – Dec'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.208)
 
IF – NYMEX (HH)
Jan'19 – Dec'19
 
Natural gas – basis swap
 
20,000 MMBtu/day
 
$(0.659)
 
PEPL
Jan'19 – Dec'19
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.625)
 
NGL MIDCON
Jan'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
Oct'18 – Dec'18
 
Natural gas – three-way collar
 
20,000 MMBtu/day
 
$3.00 - $2.50 - $3.51
 
IF – NYMEX (HH)
Oct'18 – Dec'18
 
Crude oil – swap
 
4,000 Bbl/day
 
$53.52
 
WTI – NYMEX
Oct'18 – Dec'18
 
Crude oil – price differential risk
 
500 Bbl/day
 
$7.00
 
LLS/WTI
Oct'18 – Dec'18
 
Crude oil – three-way collar
 
2,000 Bbl/day
 
$47.50 - $37.50 - $56.08
 
WTI – NYMEX
Jan'19 – Dec'19
 
Crude oil – three-way collar
 
4,000 Bbl/day
 
$61.25 - $51.25 - $72.93
 
WTI – NYMEX

After September 30, 2018, the following derivatives were entered into:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Jan'19 – Dec'19
 
Natural gas – swap
 
10,000 MMBtu/day
 
$2.850
 
IF – NYMEX (HH)
Jan'19 – Dec'19
 
Natural gas – collar
 
20,000 MMBtu/day
 
$2.63 - $3.03
 
IF – NYMEX (HH)
Jan'19 – Mar'19
 
Natural gas – three-way collar
 
10,000 MMBtu/day
 
$3.00 - $2.75 - $4.35
 
IF – NYMEX (HH)


25


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
 
September 30,
2018
 
December 31,
2017
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative asset
 
$

 
$
721

Long-term
 
Non-current derivative asset
 

 

Total derivative assets
 
 
 
$

 
$
721

 
 
 
 
Derivative Liabilities
 
 
 
 
Fair Value
 
 
Balance Sheet Location
 
September 30,
2018
 
December 31,
2017
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative liability
 
$
13,067

 
$
7,763

Long-term
 
Non-current derivative liability
 
1,542

 

Total derivative liabilities
 
 
 
$
14,609

 
$
7,763


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

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

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Income Statements for the nine months ended September 30:
Derivatives Instruments
 
Location of Gain (Loss) Recognized in
Income on Derivative
 
Amount of Gain (Loss) Recognized in Income on Derivative
 
 
 
 
2018
 
2017
 
 
 
 
(In thousands)
Commodity derivatives
 
Gain (loss) on derivatives (1)
 
$
(25,608
)
 
$
21,019

Total
 
 
 
$
(25,608
)
 
$
21,019

_______________________
(1)
Amounts settled during the 2018 and 2017 periods include net payments of $18.0 million and $0.7 million, respectively.


26


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:
 
 
September 30, 2018
 
$
830

 
$

 
$
137

 
$
693

December 31, 2017
 
$
830

 
$
102

 
$

 
$
932


During the second quarter of 2017, we received available-for-sale securities for early termination fees associated with a long-term drilling contract. We will evaluate the marketability of those equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge will be recorded, and a new cost basis established. We will review 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.


27


The following tables set forth our recurring fair value measurements:
 
 
September 30, 2018
 
 
Level 1
 
Level 2
 
Level 3
 
Effect
of Netting
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
 
Assets
 
$

 
$
1,282

 
$
88

 
$
(1,370
)
 
$

Liabilities
 

 
(8,372
)
 
(7,607
)
 
1,370

 
(14,609
)
Total commodity derivatives
 

 
(7,090
)
 
(7,519
)
 

 
(14,609
)
Equity securities
 
693

 

 

 

 
693

 
 
$
693

 
$
(7,090
)
 
$
(7,519
)
 
$

 
$
(13,916
)