10-Q 1 unt-2016630x10q.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 June 30, 2016
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]
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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [x]            No [  ]                                                     
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [x]                 Accelerated filer [ ]                 Non-accelerated filer [  ]                 Smaller reporting company [  ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [  ]            No [x]                                                     
As of July 22, 2016, 51,503,672 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 in the future, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are used to identify forward-looking statements. This report modifies and supersedes documents filed by us before this report. In addition, certain information we file with the SEC in the future will automatically update and supersede information in this report.
 
These forward-looking statements include, among others, things as:

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

2


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


3


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
 
June 30,
2016
 
December 31,
2015
 
 
(In thousands except share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
974

 
$
835

Accounts receivable, net of allowance for doubtful accounts of $5,174 and $5,199 at June 30, 2016 and December 31, 2015, respectively
 
67,506

 
79,941

Materials and supplies
 
3,324

 
3,565

Current derivative asset (Note 10)
 

 
10,186

Current income tax receivable
 
2,033

 
21,002

Current deferred tax asset
 
8,598

 
14,206

Assets held for sale
 

 
615

Prepaid expenses and other
 
6,859

 
9,908

Total current assets
 
89,294

 
140,258

Property and equipment:
 
 
 
 
Oil and natural gas properties on the full cost method:
 
 
 
 
Proved properties
 
5,420,972

 
5,401,618

Unproved properties not being amortized
 
321,191

 
337,099

Drilling equipment
 
1,567,765

 
1,567,560

Gas gathering and processing equipment
 
697,573

 
689,063

Saltwater disposal systems
 
60,527

 
60,316

Corporate land and building
 
56,149

 
49,890

Transportation equipment
 
34,055

 
40,072

Other
 
45,777

 
45,489

 
 
8,204,009

 
8,191,107

Less accumulated depreciation, depletion, amortization, and impairment
 
5,818,163

 
5,609,980

Net property and equipment
 
2,385,846

 
2,581,127

Goodwill
 
62,808

 
62,808

Non-current derivative asset (Note 10)
 

 
968

Other assets
 
14,148

 
14,681

Total assets
 
$
2,552,096

 
$
2,799,842


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

 
 
June 30,
2016
 
December 31,
2015
 
 
(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
72,744

 
$
87,413

Accrued liabilities (Note 5)
 
46,368

 
46,918

Current derivative liability (Note 10)
 
9,646

 

Current portion of other long-term liabilities (Note 6)
 
17,999

 
16,560

Total current liabilities
 
146,757

 
150,891

Long-term debt less debt issuance costs (Note 6)
 
875,051

 
918,995

Non-current derivative liability (Note 10)
 
3,420

 
285

Other long-term liabilities (Note 6)
 
103,926

 
140,341

Deferred income taxes
 
211,721

 
275,750

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

 

Common stock, $.20 par value, 175,000,000 shares authorized, 51,504,959 and 50,413,101 shares issued as of June 30, 2016 and December 31, 2015, respectively
 
10,016

 
9,831

Capital in excess of par value
 
497,312

 
486,571

Retained earnings
 
703,893

 
817,178

Total shareholders’ equity
 
1,211,221

 
1,313,580

Total liabilities and shareholders’ equity
 
$
2,552,096

 
$
2,799,842


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


5


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2016
 
2015
 
2016
 
2015
 
 
(In thousands except per share amounts)
Revenues:
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
69,190

 
$
107,256

 
$
127,464

 
$
213,325

Contract drilling
 
24,257

 
55,015

 
62,967

 
150,092

Gas gathering and processing
 
44,858

 
52,176

 
84,058

 
106,129

Total revenues
 
138,305

 
214,447

 
274,489

 
469,546

Expenses:
 
 
 
 
 
 
 
 
Oil and natural gas:
 
 
 
 
 
 
 
 
Operating costs
 
33,331

 
45,972

 
66,677

 
91,183

Depreciation, depletion, and amortization
 
30,411

 
68,101

 
62,243

 
145,219

Impairment of oil and natural gas properties (Note 2)
 
74,291

 
410,536

 
112,120

 
811,129

Contract drilling:
 
 
 
 
 
 
 
 
Operating costs
 
19,254

 
36,485

 
47,352

 
88,231

Depreciation
 
10,918

 
13,265

 
23,113

 
28,278

Impairment of contract drilling equipment (Note 3)
 

 
8,314

 

 
8,314

Gas gathering and processing:
 
 
 
 
 
 
 
 
Operating costs
 
32,381

 
40,592

 
63,447

 
84,767

Depreciation and amortization
 
11,515

 
10,848

 
22,974

 
21,542

General and administrative
 
8,382

 
9,624

 
17,097

 
18,994

Gain on disposition of assets
 
(477
)
 
(415
)
 
(669
)
 
(960
)
Total operating expenses
 
220,006

 
643,322

 
414,354

 
1,296,697

Loss from operations
 
(81,701
)
 
(428,875
)
 
(139,865
)
 
(827,151
)
Other income (expense):
 
 
 
 
 
 
 
 
Interest, net
 
(10,606
)
 
(7,956
)
 
(20,223
)
 
(15,196
)
Gain (loss) on derivatives
 
(22,672
)
 
(1,919
)
 
(11,743
)
 
4,667

Other
 
1

 
24

 
(14
)
 
22

Total other income (expense)
 
(33,277
)
 
(9,851
)
 
(31,980
)
 
(10,507
)
Loss before income taxes
 
(114,978
)
 
(438,726
)
 
(171,845
)
 
(837,658
)
Income tax expense (benefit):
 
 
 
 
 
 
 
 
Current
 

 
803

 

 
868

Deferred
 
(42,842
)
 
(165,140
)
 
(58,560
)
 
(315,783
)
Total income taxes
 
(42,842
)
 
(164,337
)
 
(58,560
)
 
(314,915
)
Net loss
 
$
(72,136
)
 
$
(274,389
)
 
$
(113,285
)
 
$
(522,743
)
Net loss per common share:
 
 
 
 
 
 
 
 
Basic
 
$
(1.44
)
 
$
(5.58
)
 
$
(2.27
)
 
$
(10.66
)
Diluted
 
$
(1.44
)
 
$
(5.58
)
 
$
(2.27
)
 
$
(10.66
)

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


6


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
Six Months Ended
 
 
June 30,
 
 
2016
 
2015
 
 
(In thousands)
OPERATING ACTIVITIES:
 
 
 
 
Net loss
 
$
(113,285
)
 
$
(522,743
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, and amortization
 
109,522

 
196,576

Impairments (Notes 2 and 3)
 
112,120

 
819,443

(Gain) loss on derivatives
 
11,743

 
(4,667
)
Cash receipts on derivatives settled
 
12,192

 
21,082

Deferred tax benefit
 
(58,560
)
 
(315,783
)
Gain on disposition of assets
 
(946
)
 
(960
)
Employee stock compensation plans
 
7,703

 
12,329

Other, net
 
(2,755
)
 
1,944

Changes in operating assets and liabilities increasing (decreasing) cash:
 
 
 
 
Accounts receivable
 
5,443

 
77,894

Accounts payable
 
24,077

 
(16,327
)
Material and supplies
 
241

 
(2,366
)
Accrued liabilities
 
3,411

 
(11,811
)
Income taxes
 
18,969

 
(1,845
)
Other, net
 
2,841

 
4,840

Net cash provided by operating activities
 
132,716

 
257,606

INVESTING ACTIVITIES:
 
 
 
 
Capital expenditures
 
(124,182
)
 
(371,572
)
Proceeds from disposition of assets
 
46,627

 
5,130

Other
 
169

 

Net cash used in investing activities
 
(77,386
)
 
(366,442
)
FINANCING ACTIVITIES:
 
 
 
 
Borrowings under credit agreement
 
150,300

 
396,000

Payments under credit agreement
 
(195,300
)
 
(281,500
)
Payments on capitalized leases
 
(1,828
)
 
(1,757
)
Tax (benefit) expense from stock compensation
 
(376
)
 
4

Book overdrafts
 
(7,987
)
 
(4,121
)
Net cash (used in) provided by financing activities
 
(55,191
)
 
108,626

Net increase (decrease) in cash and cash equivalents
 
139

 
(210
)
Cash and cash equivalents, beginning of period
 
835

 
1,049

Cash and cash equivalents, end of period
 
$
974

 
$
839

Supplemental disclosure of cash flow information:
 
 
 
 
Cash paid during the year for:
 
 
 
 
Interest paid (net of capitalized)
 
19,830

 
15,886

Income taxes
 

 
3,142

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
 
30,758

 
92,743

Non-cash reductions to oil and natural gas properties related to asset retirement obligations
 
28,884

 
5,956

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

7


UNIT CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PREPARATION AND PRESENTATION

The accompanying unaudited condensed consolidated financial statements in this report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires.

The accompanying condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This report should be read with the audited consolidated financial statements and notes in our Form 10-K, filed February 25, 2016, for the year ended December 31, 2015.

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

Balance Sheets at June 30, 2016 and December 31, 2015;
Statements of Operations for the three and six months ended June 30, 2016 and 2015; and
Statements of Cash Flows for the six months ended June 30, 2016 and 2015.

Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and accompanying notes. Actual results may differ from those estimates. Results for the six months ended June 30, 2016 and 2015 are not necessarily indicative of the results to be realized for the full year of 2016, or that we realized for the full year of 2015.

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

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

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

During the first quarter of 2016, the 12-month average commodity prices continued to decrease, resulting in a non-cash ceiling test write-down of $37.8 million pre-tax ($23.5 million, net of tax). For the second quarter of 2016, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of $74.3 million pre-tax ($46.3 million, net of tax).


8


NOTE 3 – DIVESTITURES

Oil and Natural Gas

We sold non-core oil and natural gas assets, net of related expenses, for $43.6 million during the first six months of 2016, compared to less than $0.1 million during the first six months of 2015. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

Contract Drilling

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

NOTE 4 – LOSS PER SHARE

Information related to the calculation of loss per share follows:
 
 
Loss
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
 
(In thousands except per share amounts)
For the three months ended June 30, 2016
 
 
 
 
 
 
Basic loss per common share
 
$
(72,136
)
 
50,074

 
$
(1.44
)
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)
 

 

 

Diluted loss per common share
 
$
(72,136
)
 
50,074

 
$
(1.44
)
For the three months ended June 30, 2015
 
 
 
 
 
 
Basic loss per common share
 
$
(274,389
)
 
49,148

 
$
(5.58
)
Effect of dilutive stock options, restricted stock, and SARs
 

 

 

Diluted loss per common share
 
$
(274,389
)
 
49,148

 
$
(5.58
)

Due to the net loss for the three months ended June 30, 2016, approximately 417,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the above earnings per share calculation. For the three months ended June 30, 2015, approximately 307,000 weighted average shares were excluded.

The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
 
 
Three Months Ended
 
 
June 30,
 
 
2016
 
2015
Stock options and SARs
 
240,270

 
259,085

Average exercise price
 
$
49.29

 
$
50.50


9



 
 
Loss
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
 
(In thousands except per share amounts)
For the six months ended June 30, 2016
 
 
 
 
 
 
Basic loss per common share
 
$
(113,285
)
 
49,977

 
$
(2.27
)
Effect of dilutive stock options, restricted stock, and SARs
 

 

 

Diluted loss per common share
 
$
(113,285
)
 
49,977

 
$
(2.27
)
For the six months ended June 30, 2015
 
 
 
 
 
 
Basic loss per common share
 
$
(522,743
)
 
49,063

 
$
(10.66
)
Effect of dilutive stock options, restricted stock, and SARs
 

 

 

Diluted loss per common share
 
$
(522,743
)
 
49,063

 
$
(10.66
)

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

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

 
261,270

Average exercise price
 
$
49.29

 
$
50.34


NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:
 
 
June 30,
2016
 
December 31,
2015
 
 
(In thousands)
Lease operating expenses
 
$
19,157

 
$
17,220

Taxes
 
8,722

 
3,767

Employee costs
 
7,007

 
12,641

Interest payable
 
6,213

 
6,321

Third-party credits
 
2,954

 
3,326

Derivative settlements
 
278

 

Other
 
2,037

 
3,643

Total accrued liabilities
 
$
46,368

 
$
46,918

 

10


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

Long-Term Debt

Our long-term debt consisted of the following as of the dates indicated:
 
 
June 30,
2016
 
December 31,
2015
 
 
(In thousands)
Credit agreement with an average interest rate of 3.9% and 2.6% at June 30, 2016 and December 31, 2015, respectively
 
$
236,000

 
$
281,000

6.625% senior subordinated notes due 2021
 
650,000

 
650,000

Total principal amount
 
886,000

 
931,000

Less: unamortized discount
 
(3,076
)
 
(3,338
)
Less: debt issuance costs, net
 
(7,873
)
 
(8,667
)
Total long-term debt
 
$
875,051

 
$
918,995


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

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

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

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

The credit agreement prohibits, among other things:

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


11


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

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

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

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

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

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

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

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

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

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

On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of June 30, 2016.


12


Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
 
 
June 30,
2016
 
December 31,
2015
 
 
(In thousands)
Asset retirement obligation (ARO) liability
 
$
70,926

 
$
98,297

Capital lease obligations
 
20,710

 
22,466

Workers’ compensation
 
15,258

 
16,551

Separation benefit plans
 
6,386

 
9,886

Deferred compensation plan
 
4,430

 
4,244

Gas balancing liability
 
3,805

 
5,047

Other
 
410

 
410

 
 
121,925

 
156,901

Less current portion
 
17,999

 
16,560

Total other long-term liabilities
 
$
103,926

 
$
140,341


Estimated annual principal payments under the terms of debt and other long-term liabilities during each of the five successive twelve month periods beginning July 1, 2016 (and through 2021) are $18.0 million, $44.3 million, $10.2 million, $244.1 million, and $658.7 million, respectively.

Capital Leases

During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The current portion of our capital lease obligations of $3.6 million is included in current portion of other long-term liabilities and the non-current portion of $17.1 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of June 30, 2016. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $8.6 million and $2.3 million, respectively at June 30, 2016. Annual payments, net of maintenance and interest, average $4.0 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their fair market value at that time.

Future payments required under the capital leases at June 30, 2016:
 
 
Amount
Ending June 30,
 
(In thousands)
2017
 
$
6,168

2018
 
6,168

2019
 
6,168

2020
 
6,168

2021 and thereafter
 
6,853

Total future payments
 
31,525

Less payments related to:
 
 
Maintenance
 
8,552

Interest
 
2,263

Present value of future minimum payments
 
$
20,710



13


NOTE 7 – ASSET RETIREMENT OBLIGATIONS

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

The following table shows certain information about our AROs for the periods indicated:
 
 
Six Months Ended
 
 
June 30,
 
 
2016
 
2015
 
 
(In thousands)
ARO liability, January 1:
 
$
98,297

 
$
100,567

Accretion of discount
 
1,513

 
1,757

Liability incurred
 
212

 
5,986

Liability settled
 
(605
)
 
(1,566
)
Liability sold (1)
 
(10,308
)
 
(246
)
Revision of estimates (2)
 
(18,183
)

(10,130
)
ARO liability, June 30:
 
70,926

 
96,368

Less current portion
 
3,523

 
3,277

Total long-term ARO
 
$
67,403

 
$
93,091

_______________________ 
(1)
We sold approximately 1,150 wells to unaffiliated third-parties during the first six months of 2016.
(2)
Plugging liability estimates were revised in both 2016 and 2015 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS

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

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

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

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

14


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

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-12, "Narrow-Scope Improvements and Practical Expedients," which provides clarifying guidance in certain areas and adds some practical expedients. Also in May 2016, the FASB issued ASU 2016-11, "Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting." This ASU rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities— Oil and Gas, effective upon the adoption of Topic 606, Revenue from Contracts with Customers. In April 2016, the FASB issued ASU 2016-10, "Identifying Performance Obligations and Licensing," which amends the revenue guidance on identifying performance obligations and accounting for licenses of intellectual property. The FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are in the process of evaluating the impact it will have on our financial statements.

NOTE 9 – STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2016
 
2015
 
2016
 
2015
 
 
(In millions)
Recognized stock compensation expense
 
$
2.0

 
$
4.8

 
$
5.3

 
$
9.1

Capitalized stock compensation cost for our oil and natural gas properties
 
0.4

 
1.0

 
1.2

 
1.9

Tax benefit on stock based compensation
 
0.7

 
1.7

 
2.0

 
3.4


The remaining unrecognized compensation cost related to unvested awards at June 30, 2016 is approximately $10.9 million, of which $1.7 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.7 of a year.

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


15


We did not grant any SARs or stock options during either of the three or six month periods ending June 30, 2016 and 2015. The following tables show 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, 2016
 
June 30, 2015
 
 
Time
Vested
 
Performance Vested
 
Time
Vested
 
Performance Vested
Shares granted:
 
 
 
 
 
 
 
 
Employees
 

 

 

 

Non-employee directors
 
90,000

 

 
25,848

 

 
 
90,000

 

 
25,848

 

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

 
$

 
$

 
$

Non-employee directors
 
0.9

 

 
0.9

 

 
 
$
0.9

 
$

 
$
0.9

 
$

Percentage of shares granted expected to be distributed:
 
 
 
 
 
 
 
 
Employees
 
N/A

 
N/A

 
N/A

 
N/A

Non-employee directors
 
100
%
 
N/A

 
100
%
 
N/A

_______________________
(1)
Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)
 
 
Six Months Ended
 
Six Months Ended
 
 
June 30, 2016
 
June 30, 2015
 
 
Time
Vested
 
Performance Vested
 
Time
Vested
 
Performance Vested
Shares granted:
 
 
 
 
 
 
 
 
Employees
 
486,578

 
152,373

 
576,361

 
148,081

Non-employee directors
 
90,000

 

 
25,848

 

 
 
576,578

 
152,373

 
602,209

 
148,081

Estimated fair value (in millions):(1)
 
 
 
 
 
 
 
 
Employees
 
$
2.6

 
$
0.8

 
$
18.5

 
$
5.1

Non-employee directors
 
0.9

 

 
0.9

 

 
 
$
3.5

 
$
0.8

 
$
19.4

 
$
5.1

Percentage of shares granted expected to be distributed:
 
 
 
 
 
 
 
 
Employees
 
94
%
 
70
%
 
94
%
 
3
%
Non-employee directors
 
100
%
 
N/A

 
100
%
 
N/A

_______________________
(1)
Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

The time vested restricted stock awards granted during the first six months of 2016 and 2015 are being recognized over a three year vesting period. During the first quarter of 2016, there were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three year vesting period based on the company's achievement of cash flow to total assets performance measurement each year and will range from 0% to 200%. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2016 awards for the first six months of 2016 was $0.7 million.


16


NOTE 10 – DERIVATIVES

Commodity Derivatives

We have entered into various types of derivative transactions covering some of our projected natural gas and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of June 30, 2016, our derivative transactions comprised the following hedges:

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

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

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

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

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

At June 30, 2016, we had the following derivatives outstanding:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Jul’16 – Dec’16
 
Natural gas – swap
 
45,000 MMBtu/day
 
$2.596
 
IF – NYMEX (HH)
Jan’17 – Dec'17
 
Natural gas – swap
 
60,000 MMBtu/day
 
$2.960
 
IF – NYMEX (HH)
Jan’18 – Dec'18
 
Natural gas – swap
 
10,000 MMBtu/day
 
$3.025
 
IF – NYMEX (HH)
Jan’17 – Dec'17
 
Natural gas – basis swap
 
20,000 MMBtu/day
 
$(0.215)
 
IF – NYMEX (HH)
Jan’18 – Dec'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.208)
 
IF – NYMEX (HH)
Jul’16 – Dec'16
 
Natural gas – collar
 
42,000 MMBtu/day
 
$2.40 - $2.88
 
IF – NYMEX (HH)
Jan’17 – Oct'17
 
Natural gas – collar
 
10,000 MMBtu/day
 
$2.75 - $2.95
 
IF – NYMEX (HH)
Jul’16 – Dec'16
 
Natural gas – three-way collar
 
13,500 MMBtu/day
 
$2.70 - $2.20 - $3.26
 
IF – NYMEX (HH)
Jan’17 – Dec'17
 
Natural gas – three-way collar
 
15,000 MMBtu/day
 
$2.50 - $2.00 - $3.32
 
IF – NYMEX (HH)
Jul’16 – Sep'16
 
Crude oil – swap
 
1,000 Bbl/day
 
$48.45
 
WTI – NYMEX
Jul’16 – Sep'16
 
Crude oil – collar
 
2,450 Bbl/day
 
$44.44 - $52.46
 
WTI – NYMEX
Oct’16 – Dec'16
 
Crude oil – collar
 
1,450 Bbl/day
 
$47.50 - $56.40
 
WTI – NYMEX
Jul’16 – Dec'16
 
Crude oil – three-way collar
 
700 Bbl/day
 
$46.50 - $35.00 - $57.00
 
WTI – NYMEX
Jul’16 – Dec'16
 
Crude oil – three-way collar (1)
 
700 Bbl/day
 
$47.50 - $35.00 - $63.50
 
WTI – NYMEX
Jan’17 – Dec'17
 
Crude oil – three-way collar
 
750 Bbl/day
 
$50.00 - $37.50 - $63.90
 
WTI – NYMEX
_______________________
(1)
We pay our counterparty a premium, which can be and is being deferred until settlement.

17



After June 30, 2016, we entered into the following derivatives:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Jan’17 – Oct'17
 
Natural gas – collar
 
10,000 MMBtu/day
 
$3.00 - $3.24
 
IF – NYMEX (HH)

The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
 
 
 
 
Derivative Assets
 
 
 
 
Fair Value
 
 
Balance Sheet Location
 
June 30,
2016
 
December 31,
2015
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative asset
 
$

 
$
10,186

Long-term
 
Non-current derivative asset
 

 
968

Total derivative assets
 
 
 
$

 
$
11,154


 
 
 
 
Derivative Liabilities
 
 
 
 
Fair Value
 
 
Balance Sheet Location
 
June 30,
2016
 
December 31,
2015
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative liability
 
$
9,646

 
$

Long-term
 
Non-current derivative liability
 
3,420

 
285

Total derivative liabilities
 
 
 
$
13,066

 
$
285


If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets.

Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the three months ended June 30:
Derivatives Instruments
 
Location of Loss Recognized in
Income on Derivative
 
Amount of Loss Recognized in Income on Derivative
 
 
 
 
2016
 
2015
 
 
 
 
(In thousands)
Commodity derivatives
 
Gain (loss) on derivatives (1)
 
$
(22,672
)
 
$
(1,919
)
Total
 
 
 
$
(22,672
)
 
$
(1,919
)
_______________________
(1)
Amounts settled during the 2016 and 2015 periods include gains of $5.1 million and $10.1 million, respectively.

18


Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the six months ended June 30:
Derivatives Instruments
 
Location of Gain (Loss) Recognized in
Income on Derivative
 
Amount of Gain (Loss) Recognized in Income on Derivative
 
 
 
 
2016
 
2015
 
 
 
 
(In thousands)
Commodity derivatives
 
Gain (loss) on derivatives (1)
 
$
(11,743
)
 
$
4,667

Total
 
 
 
$
(11,743
)
 
$
4,667

_______________________
(1)
Amounts settled during the 2016 and 2015 periods include gains of $12.2 million and $21.1 million, respectively.

NOTE 11 – FAIR VALUE MEASUREMENTS

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

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

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

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

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

The following tables set forth our recurring fair value measurements:
 
 
June 30, 2016
 
 
Level 2
 
Level 3
 
Effect
of Netting
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
Assets
 
$
435

 
$
515

 
$
(950
)
 
$

Liabilities
 
(8,740
)
 
(5,276
)
 
950

 
(13,066
)
 
 
$
(8,305
)
 
$
(4,761
)
 
$

 
$
(13,066
)
 
 
December 31, 2015
 
 
Level 2
 
Level 3
 
 
Effect
of Netting
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
Assets
 
$
2,794

 
$
10,145

 
 
$
(1,785
)
 
$
11,154

Liabilities
 
(1,019
)
 
(1,051
)
 
 
1,785

 
(285
)
 
 
$
1,775

 
$
9,094

 
 
$

 
$
10,869



19


All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of June 30, 2016.

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

Level 2 Fair Value Measurements

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

Level 3 Fair Value Measurements

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

The following tables are reconciliations of our level 3 fair value measurements: 
 
 
Net Derivatives
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2016
 
2015
 
2016
 
2015
 
 
(In thousands)
Beginning of period
 
$
9,983

 
$
857

 
$
9,094

 
$
3,355

Total gains or losses (realized and unrealized):
 
 
 
 
 
 
 
 
Included in earnings (1)
 
(12,322
)
 
111

 
(6,334
)
 
888

Settlements
 
(2,422
)
 
(761
)
 
(7,521
)
 
(4,036
)
End of period
 
$
(4,761
)
 
$
207

 
$
(4,761
)
 
$
207

Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period
 
$
(14,744
)
 
$
(650
)
 
$
(13,855
)
 
$
(3,148
)
_______________________
(1)
Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives.

The following table provides quantitative information about our Level 3 unobservable inputs at June 30, 2016:
Commodity (1)
 
Fair Value
 
Valuation Technique
 
Unobservable Input
 
Range
 
 
(In thousands)
 
 
 
 
 
 
Oil collars
 
$
(151
)
 
Discounted cash flow
 
Forward commodity price curve
 
$0.07 - $5.31
Oil three-way collars
 
$
301

 
Discounted cash flow
 
Forward commodity price curve
 
$0.00 - $6.35
Natural gas collar
 
$
(3,253
)
 
Discounted cash flow
 
Forward commodity price curve
 
$0.00 - $0.90
Natural gas three-way collars
 
$
(1,658
)
 
Discounted cash flow
 
Forward commodity price curve
 
$0.00 - $0.51
 _______________________
(1)
The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Based on our valuation at June 30, 2016, we determined that risk of non-performance by our counterparties was immaterial.


20


Fair Value of Other Financial Instruments

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

At June 30, 2016, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short term nature.

Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at June 30, 2016 and December 31, 2015 was $236.0 million and $281.0 million, respectively. This debt would be classified as Level 2.

The carrying amounts of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015 were $639.1 million and $638.0 million, respectively. We estimate the fair value of these Notes using quoted marked prices at June 30, 2016 and December 31, 2015 were $505.4 million and $455.5 million, respectively. These Notes would be classified as Level 2.

Fair Value of Non-Financial Instruments

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

NOTE 12 – INDUSTRY SEGMENT INFORMATION

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

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

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

21


The following table provides certain information about the operations of each of our segments:

 
 
Three Months Ended June 30, 2016
 
 
Oil and Natural Gas
 
Contract Drilling
 
Mid-stream
 
Other
 
Eliminations
 
Total Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
69,190

 
$

 
$

 
$

 
$

 
$
69,190

Contract drilling
 

 
24,257

 

 

 

 
24,257

Gas gathering and processing
 

 

 
56,533

 

 
(11,675
)
 
44,858

Total revenues
 
69,190

 
24,257

 
56,533

 

 
(11,675
)
 
138,305

Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs
 
35,555

 

 

 

 
(2,224
)
 
33,331

Depreciation, depletion, and amortization
 
30,411

 

 

 

 

 
30,411

Impairment of oil and natural gas properties
 
74,291

 

 

 

 

 
74,291

Contract drilling:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs
 

 
19,254

 

 

 

 
19,254

Depreciation
 

 
10,918

 

 

 

 
10,918

Gas gathering and processing:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs
 

 

 
41,832

 

 
(9,451
)
 
32,381

Depreciation and amortization
 

 

 
11,515

 

 

 
11,515

Total expenses
 
140,257

 
30,172

 
53,347

 

 
(11,675
)
 
212,101

Total operating income (loss) (1)
 
(71,067
)
 
(5,915
)
 
3,186

 

 

 
(73,796
)
General and administrative expense
 

 

 

 
(8,382
)
 

 
(8,382
)
Gain (loss) on disposition of assets
 
(324
)
 
815

 

 
(14
)
 

 
477

Loss on derivatives
 

 

 

 
(22,672
)
 

 
(22,672
)
Interest expense, net
 

 

 

 
(10,606
)
 

 
(10,606
)
Other
 

 

 

 
1

 

 
1

Income (loss) before income taxes
 
$
(71,391
)
 
$
(5,100
)
 
$
3,186

 
$
(41,673
)
 
$

 
$
(114,978
)
_______________________
(1)
Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, (gain) loss on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes.


22


 
 
Three Months Ended June 30, 2015
 
 
Oil and Natural Gas
 
Contract Drilling
 
Mid-stream
 
Other
 
Eliminations
 
Total Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
107,256

 
$

 
$

 
$

 
$

 
$
107,256

Contract drilling
 

 
60,813

 

 

 
(5,798
)
 
55,015

Gas gathering and processing
 

 

 
69,163

 

 
(16,987
)
 
52,176

Total revenues
 
107,256

 
60,813

 
69,163

 

 
(22,785
)
 
214,447

Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs
 
47,179

 

 

 

 
(1,207
)
 
45,972

Depreciation, depletion, and amortization
 
68,101

 

 

 

 

 
68,101

Impairment of oil and natural gas properties
 
410,536

 

 

 

 

 
410,536

Contract drilling:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs
 

 
41,746

 

 

 
(5,261
)
 
36,485

Depreciation
 

 
13,265

 

 

 

 
13,265

Impairment of contract drilling properties
 

 
8,314

 

 

 

 
8,314

Gas gathering and processing:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs
 

 

 
56,372

 

 
(15,780
)
 
40,592

Depreciation and amortization
 

 

 
10,848

 

 

 
10,848

Total expenses
 
525,816

 
63,325

 
67,220

 

 
(22,248
)
 
634,113

Total operating income (loss)(1)
 
(418,560
)
 
(2,512
)
 
1,943

 

 
(537
)
 
(419,666
)
General and administrative expense
 

 

 

 
(9,624
)
 

 
(9,624
)
Gain (loss) on disposition of assets
 

 
(50
)
 
465

 

 

 
415

Loss on derivatives
 

 

 

 
(1,919
)
 

 
(1,919
)
Interest expense, net
 

 

 

 
(7,956
)
 

 
(7,956
)
Other
 

 

 

 
24

 

 
24

Income (loss) before income taxes
 
$
(418,560
)
 
$
(2,562
)
 
$
2,408

 
$
(19,475
)
 
$
(537
)
 
$
(438,726
)
_______________________
(1)
Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (