10-Q 1 unt-2017930x10q.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, 2017
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]
image2a01a09.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 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [ ]    Accelerated filer [ x ]    Non-accelerated filer (Do not check if a smaller reporting company) [  ]
Smaller reporting company [  ]    Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    [ ]        

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [  ]            No [x]                                                     
As of October 20, 2017, 52,879,660 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; 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 result in substantial expenditures and divert management's attention; and
other factors, most of which are beyond our control.
You should not place undue reliance on these forward-looking statements. Except as required by law, we disclaim any intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after the date of this document to reflect unanticipated events.

2


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
 
September 30,
2017
 
December 31,
2016
 
 
(In thousands except share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
822

 
$
893

Accounts receivable, net of allowance for doubtful accounts of $2,393 and $3,773 at September 30, 2017 and December 31, 2016, respectively
 
116,292

 
83,954

Materials and supplies
 
3,323

 
3,340

Current derivative asset (Note 10)
 
1,064

 

Current income tax receivable
 
114

 
99

Current deferred tax asset (Note 8)
 

 
25,211

Prepaid expenses and other
 
7,351

 
7,699

Total current assets
 
128,966

 
121,196

Property and equipment:
 
 
 
 
Oil and natural gas properties on the full cost method:
 
 
 
 
Proved properties
 
5,605,974

 
5,446,305

Unproved properties not being amortized
 
337,064

 
314,867

Drilling equipment
 
1,593,835

 
1,565,268

Gas gathering and processing equipment
 
715,864

 
705,859

Saltwater disposal systems
 
62,387

 
60,638

Corporate land and building
 
59,079

 
59,066

Transportation equipment
 
29,731

 
32,842

Other
 
53,308

 
48,590

 
 
8,457,242

 
8,233,435

Less accumulated depreciation, depletion, amortization, and impairment
 
6,099,229

 
5,952,330

Net property and equipment
 
2,358,013

 
2,281,105

Goodwill
 
62,808

 
62,808

Non-current derivative asset (Note 10)
 

 
377

Other assets
 
16,085

 
13,817

Total assets
 
$
2,565,872

 
$
2,479,303


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

3


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

 
 
September 30,
2017
 
December 31,
2016
 
 
(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
116,152

 
$
88,793

Accrued liabilities (Note 5)
 
60,132

 
39,651

Current derivative liability (Note 10)
 
636

 
21,564

Current portion of other long-term liabilities (Note 6)
 
14,227

 
14,907

Total current liabilities
 
191,147

 
164,915

Long-term debt less debt issuance costs (Note 6)
 
803,833

 
800,917

Non-current derivative liability (Note 10)
 
282

 
415

Other long-term liabilities (Note 6)
 
105,468

 
103,064

Deferred income taxes (Note 8)
 
213,237

 
215,922

Commitments and contingencies (Note 12)
 

 

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

 

Common stock, $.20 par value, 175,000,000 shares authorized, 52,879,660 and 51,494,318 shares issued as of September 30, 2017 and December 31, 2016, respectively
 
10,277

 
10,016

Capital in excess of par value
 
531,328

 
502,500

Accumulated other comprehensive income (Note 13)
 
53

 

Retained earnings
 
710,247

 
681,554

Total shareholders’ equity
 
1,251,905

 
1,194,070

Total liabilities and shareholders’ equity
 
$
2,565,872

 
$
2,479,303


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


4


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(In thousands except per share amounts)
Revenues:
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
85,470

 
$
78,854

 
$
256,241

 
$
206,318

Contract drilling
 
51,619

 
25,819

 
128,059

 
88,786

Gas gathering and processing
 
51,399

 
48,735

 
150,493

 
132,793

Total revenues
 
188,488

 
153,408

 
534,793

 
427,897

Expenses:
 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
 
Oil and natural gas
 
33,911

 
26,014

 
95,873

 
92,691

Contract drilling
 
34,747

 
19,137

 
91,213

 
66,489

Gas gathering and processing
 
38,116

 
35,738

 
111,862

 
99,185

Total operating costs
 
106,774

 
80,889

 
298,948

 
258,365

Depreciation, depletion, and amortization
 
54,533

 
49,969

 
151,545

 
158,437

Impairments (Note 2)
 

 
49,443

 

 
161,563

General and administrative
 
9,235

 
8,852

 
26,902

 
25,811

Gain on disposition of assets
 
(81
)
 
(154
)
 
(1,153
)
 
(823
)
Total operating expenses
 
170,461

 
188,999

 
476,242

 
603,353

Income (loss) from operations
 
18,027

 
(35,591
)
 
58,551

 
(175,456
)
Other income (expense):
 
 
 
 
 
 
 
 
Interest, net
 
(9,944
)
 
(10,002
)
 
(28,807
)
 
(30,225
)
Gain (loss) on derivatives
 
(2,614
)
 
6,969

 
21,019

 
(4,774
)
Other, net
 
5

 
3

 
14

 
(11
)
Total other income (expense)
 
(12,553
)
 
(3,030
)
 
(7,774
)
 
(35,010
)
Income (loss) before income taxes
 
5,474

 
(38,621
)
 
50,777

 
(210,466
)
Income tax expense (benefit):
 
 
 
 
 
 
 
 
Deferred
 
1,769

 
(14,599
)
 
22,084

 
(73,159
)
Total income taxes
 
1,769

 
(14,599
)
 
22,084

 
(73,159
)
Net income (loss)
 
$
3,705

 
$
(24,022
)
 
$
28,693

 
$
(137,307
)
Net income (loss) per common share:
 
 
 
 
 
 
 
 
Basic
 
$
0.07

 
$
(0.48
)
 
$
0.56

 
$
(2.75
)
Diluted
 
$
0.07

 
$
(0.48
)
 
$
0.56

 
$
(2.75
)

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


5


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands)
Net income (loss)
$
3,705

 
$
(24,022
)
 
$
28,693

 
$
(137,307
)
Other comprehensive income, net of taxes:
 
 
 
 
 
 
 
Unrealized appreciation on securities, net of tax of $20, $0, $32, and $0
33

 

 
53

 

Comprehensive income (loss)
$
3,738

 
$
(24,022
)
 
$
28,746

 
$
(137,307
)

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)
 
 
Nine Months Ended
 
 
September 30,
 
 
2017
 
2016
 
 
(In thousands)
OPERATING ACTIVITIES:
 
 
 
 
Net income (loss)
 
$
28,693

 
$
(137,307
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, and amortization
 
151,545

 
158,437

Impairments (Note 2)
 

 
161,563

Amortization of debt issuance costs and debt discount (Note 6)
 
1,616

 
1,586

(Gain) loss on derivatives
 
(21,019
)
 
4,774

Cash (payments) receipts on derivatives settled, net
 
(729
)
 
11,735

Deferred tax expense (benefit)
 
22,084

 
(73,159
)
Gain on disposition of assets
 
(1,153
)
 
(1,100
)
Stock compensation plans
 
12,478

 
10,664

Other, net
 
1,397

 
(3,055
)
Changes in operating assets and liabilities increasing (decreasing) cash:
 
 
 
 
Accounts receivable
 
(36,381
)
 
759

Accounts payable
 
4,873

 
26,940

Material and supplies
 
17

 
231

Accrued liabilities
 
20,280

 
14,073

Income taxes
 
(15
)
 
20,636

Other, net
 
1,106

 
985

Net cash provided by operating activities
 
184,792

 
197,762

INVESTING ACTIVITIES:
 
 
 
 
Capital expenditures
 
(167,392
)
 
(154,558
)
Producing properties and other acquisitions (Note 3)
 
(55,429
)
 

Proceeds from disposition of assets
 
20,137

 
46,880

Other
 
(1,500
)
 
169

Net cash used in investing activities
 
(204,184
)
 
(107,509
)
FINANCING ACTIVITIES:
 
 
 
 
Borrowings under credit agreement
 
251,401

 
195,700

Payments under credit agreement
 
(250,100
)
 
(261,700
)
Payments on capitalized leases
 
(2,967
)
 
(2,756
)
Proceeds from common stock issued, net of issue costs (Note 13)
 
18,623

 

Tax benefit from stock compensation
 

 
(376
)
Book overdrafts
 
2,364

 
(21,043
)
Net cash provided by (used in) financing activities
 
19,321

 
(90,175
)
Net increase (decrease) in cash and cash equivalents
 
(71
)
 
78

Cash and cash equivalents, beginning of period
 
893

 
835

Cash and cash equivalents, end of period
 
$
822

 
$
913


7


Supplemental disclosure of cash flow information:
 
 
 
 
Cash paid during the year for:
 
 
 
 
Interest paid (net of capitalized)
 
14,601

 
16,650

Income taxes
 

 

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
 
(20,122
)
 
36,934

Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations
 
(3,203
)
 
29,423

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

8


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.

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 28, 2017, for the year ended December 31, 2016.

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 the following:

Balance Sheets at September 30, 2017 and December 31, 2016;
Statements of Operations for the three and nine months ended September 30, 2017 and 2016;
Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 and 2016; and
Statements of Cash Flows for the nine months ended September 30, 2017 and 2016.

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 notes. Actual results may differ from those estimates. Results for the nine months ended September 30, 2017 and 2016 are not necessarily indicative of the results to be realized for the full year of 2017, or that we realized for the full year of 2016.

Certain amounts in the 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.

We incurred non-cash ceiling test write-downs in the first nine months of 2016 of $161.6 million ($100.6 million net of tax). We did not have a write-down in the first nine months of 2017.

NOTE 3 – ACQUISITIONS AND DIVESTITURES

Acquisitions

On April 3, 2017, we closed on an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million.

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

9


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

We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations, which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the adjusted purchase price and the estimated values of assets acquired and liabilities assumed. It is based on information available to us at the time these unaudited condensed consolidated financial statements were prepared. We believe these estimates are reasonable; however, the estimates are subject to change as additional information becomes available and is assessed by us (in thousands):
Adjusted Purchase Price
 
Total consideration given
$
54,332

 
 
Adjusted Allocation of Purchase Price
 
Oil and natural gas properties included in the full cost pool:
 
Proved oil and natural gas properties
$
43,745

Undeveloped oil and natural gas properties
8,650

Total oil and natural gas properties included in the full cost pool (1)
52,395

Gas gathering equipment and other
2,340

Asset retirement obligation
(403
)
Fair value of net assets acquired
$
54,332

(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.
    
The pro forma effects of this acquired business is immaterial to the results of operations.

During the third quarter of 2017, we had approximately $2.1 million in other acquisitions.

Divestitures

We sold non-core oil and natural gas assets, net of related expenses, for $18.0 million during the first nine months of 2017, compared to $43.6 million during the first nine months of 2016. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

NOTE 4 – EARNINGS (LOSS) PER SHARE

Information related to the calculation of earnings (loss) per share follows:
 
 
Earnings (Loss)
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
 
(In thousands except per share amounts)
For the three months ended September 30, 2017
 
 
 
 
 
 
Basic earnings per common share
 
$
3,705

 
51,386

 
$
0.07

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

 
586

 

Diluted earnings per common share
 
$
3,705

 
51,972

 
$
0.07

For the three months ended September 30, 2016
 
 
 
 
 
 
Basic loss per common share
 
$
(24,022
)
 
50,081

 
$
(0.48
)
Effect of dilutive stock options, restricted stock, and SARs
 

 

 

Diluted loss per common share
 
$
(24,022
)
 
50,081

 
$
(0.48
)


10


Due to the net loss for the three months ended September 30, 2016, approximately 546,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the calculation above.

The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
 
 
Three Months Ended
 
 
September 30,
 
 
2017
 
2016
Stock options and SARs
 
178,755

 
240,270

Average exercise price
 
$
47.75

 
$
49.29


 
 
Earnings (Loss)
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
 
(In thousands except per share amounts)
For the nine months ended September 30, 2017
 
 
 
 
 
 
Basic earnings per common share
 
$
28,693

 
51,019

 
$
0.56

Effect of dilutive stock options, restricted stock, and SARs
 

 
550

 

Diluted earnings per common share
 
$
28,693

 
51,569

 
$
0.56

For the nine months ended September 30, 2016
 
 
 
 
 
 
Basic loss per common share
 
$
(137,307
)
 
50,012

 
$
(2.75
)
Effect of dilutive stock options, restricted stock, and SARs
 

 

 

Diluted loss per common share
 
$
(137,307
)
 
50,012

 
$
(2.75
)

Because of the net loss for the nine months ended September 30, 2016, approximately 424,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the calculation above.

The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
 
 
Nine Months Ended
 
 
September 30,
 
 
2017
 
2016
Stock options and SARs
 
178,755

 
240,270

Average exercise price
 
$
47.75

 
$
49.29


NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of:
 
 
September 30,
2017
 
December 31,
2016
 
 
(In thousands)
Interest payable
 
$
17,480

 
$
6,524

Employee costs
 
14,526

 
15,394

Lease operating expenses
 
12,686

 
10,075

Taxes
 
9,982

 
2,219

Third-party credits
 
2,184

 
2,998

Other
 
3,274

 
2,441

Total accrued liabilities
 
$
60,132

 
$
39,651

 

11


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,
2017
 
December 31,
2016
 
 
(In thousands)
Credit agreement with an average interest rate of 3.3% and 2.8% at September 30, 2017 and December 31, 2016, respectively
 
$
162,100

 
$
160,800

6.625% senior subordinated notes due 2021
 
650,000

 
650,000

Total principal amount
 
812,100

 
810,800

Less: unamortized discount
 
(2,380
)
 
(2,804
)
Less: debt issuance costs, net
 
(5,887
)
 
(7,079
)
Total long-term debt
 
$
803,833

 
$
800,917


Credit Agreement. Our Senior Credit Agreement (credit agreement) is scheduled to mature on April 10, 2020. Under the credit agreement, the amount we can borrow is the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed $875.0 million. Our borrowing base and elected commitment is $475.0 million. 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 origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. Under the credit agreement, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our mid-stream 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. The October 2017 redetermination did not result in any changes. 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 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 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 September 30, 2017, we had $162.1 million of outstanding borrowings under our credit agreement.

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

The credit agreement prohibits, among other things:

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

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

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

12



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

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

Beginning with the quarter ending June 30, 2019, and for each following quarter, 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 September 30, 2017, we were in compliance with the credit agreement covenants.

6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million, 6.625% senior subordinated notes (the Notes) outstanding. Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes 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 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.

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, 2017.



13


Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
 
 
September 30,
2017
 
December 31,
2016
 
 
(In thousands)
Asset retirement obligation (ARO) liability
 
$
75,485

 
$
70,170

Capital lease obligations
 
16,161

 
18,918

Workers’ compensation
 
13,420

 
15,163

Separation benefit plans
 
6,020

 
4,943

Deferred compensation plan
 
5,287

 
4,578

Gas balancing liability
 
3,322

 
3,789

Other
 

 
410

 
 
119,695

 
117,971

Less current portion
 
14,227

 
14,907

Total other long-term liabilities
 
$
105,468

 
$
103,064


Estimated annual principal payments under the terms of debt and other long-term liabilities during the five successive twelve month periods beginning October 1, 2017 (and through 2022) are $14.2 million, $48.3 million, $172.4 million, $657.0 million, and $2.5 million, respectively.

Capital Leases

In 2014, our mid-stream segment 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 $3.8 million current portion of our capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $12.4 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $6.3 million and $1.3 million, respectively, at September 30, 2017. Annual payments, net of maintenance and interest, average $4.1 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value.

Future payments required under the capital leases at September 30, 2017:
 
 
Amount
Beginning October 1,
 
(In thousands)
2017
 
$
6,168

2018
 
6,168

2019
 
6,168

2020
 
5,310

Total future payments
 
23,814

Less payments related to:
 
 
Maintenance
 
6,320

Interest
 
1,333

Present value of future minimum payments
 
$
16,161



14


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,
 
 
2017
 
2016
 
 
(In thousands)
ARO liability, January 1:
 
$
70,170

 
$
98,297

Accretion of discount
 
2,112

 
2,147

Liability incurred
 
1,123

 
311

Liability settled
 
(1,350
)
 
(874
)
Liability sold (1)
 
(1,563
)
 
(10,758
)
Revision of estimates (2)
 
4,993


(18,102
)
ARO liability, September 30:
 
75,485

 
71,021

Less current portion
 
2,947

 
3,498

Total long-term ARO
 
$
72,538

 
$
67,523

_______________________ 
(1)
We sold our interest in a number of non-core wells to unaffiliated third-parties during the first nine months of 2017 and 2016, respectively.
(2)
Plugging liability estimates were revised in both 2017 and 2016 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. The FASB issued ASU 2017-09, to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms and conditions of a share-based payment award. The amendments are effective for reporting periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements.

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

Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements.

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

Leases. The FASB has issued ASU 2016-02. The amendments will require lessees 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

15


December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases of mineral rights. We are in the process of evaluating the impact these amendments will have on our financial statements.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. These amendments affect any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the amendments 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. ASU 2014-09 has been amended several times pre-issuance, which will be codified in the new Topic 606, and it is effective January 1. 2018. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. We will adopt these amendments January 1, 2018.

The new revenue standard provides a five-step analysis of transactions to determine the amount and timing of revenue recognition. Entities can choose to apply Topic 606 using either the full retrospective approach or a modified retrospective approach. We plan to adopt using the modified retrospective approach, which will result in a cumulative effect adjustment upon adoption.

Currently, management believes the effect of adoption will not have a material effect on our statement of operations or our balance sheet, as the timing of revenue recognized will not be materially modified, but the adoption will result in more robust footnote disclosures in regards to revenue. We anticipate a cumulative effect of applying the new revenue standard as an adjustment to the opening balance of retained earnings at the beginning of 2018 in relation to certain mid-stream segment and contract drilling segment contracts that include adjustments to the timing of revenue recognition of certain demand fee and mobilization/demobilization expenses and revenue, respectively. We believe this adjustment will not be material due to the short-term nature of the majority of our current contract drilling segment contracts and the limited number of mid-stream segment contracts with demand fees that we anticipate to be in place at the adoption date. Part of our review included evaluation of the following issues:

Based on an analysis of whether the transportation of gas is a performance obligation that occurs at a point in time or over time, the timing of when we recognize certain revenue elements will change. Specifically related to our mid-stream segment, certain fees that are collectible in the early stages of a contract will be recognized over the life of the contract because these fees are part of the single performance obligation associated with the contract.

Certain of our contracts include promises to deliver a minimum volume of commodity to the customer over a defined period of time. If we do not meet this commitment, a deficiency fee is payable to the customer. Topic 606 requires that these types of arrangements represent variable consideration related to the sale of the commodity, and requires that we include an estimate of any deficiency fees expected within revenue, rather than as operating costs. In addition, we will also be required to analyze fees that are billable for deficiencies in minimum volume commitments from customers for our mid-stream segment. In these instances, we will assess the likelihood of earning these fees each reporting period based on the customer’s performance and recognize variable revenue at the time it is not expected to be subject to a significant reversal.

Adopted Standards

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

Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments primarily

16


impact classification within the statement of cash flows between financial and operating activities. This did not have a material impact on our financial statements.

NOTE 9 –STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(In millions)
Recognized stock compensation expense
 
$
3.2

 
$
1.9

 
$
9.0

 
$
7.2

Capitalized stock compensation cost for our oil and natural gas properties
 
0.5

 
0.4

 
1.3

 
1.6

Tax benefit on stock based compensation
 
1.2

 
0.7

 
3.4

 
2.7


The remaining unrecognized compensation cost related to unvested awards at September 30, 2017 is approximately $14.2 million, of which $1.7 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is one 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) as well as to non-employee directors. A total of 7,000,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan with 2,000,000 shares being the maximum number of shares that can be issued as "incentive stock options."

We did not grant any SARs or stock options during either of the three or nine month periods ending September 30, 2017 or 2016. We did not grant any restricted stock awards during either of the three month periods ending September 30, 2017 or 2016. The following 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, 2017
 
September 30, 2016
 
 
Time
Vested
 
Performance Vested
 
Time
Vested
 
Performance Vested
Shares granted:
 
 
 
 
 
 
 
 
Employees
 
475,799

 
173,373

 
486,578

 
152,373

Non-employee directors
 
49,104

 

 
90,000

 

 
 
524,903

 
173,373

 
576,578

 
152,373

Estimated fair value (in millions):(1)
 
 
 
 
 
 
 
 
Employees
 
$
11.8

 
$
4.5

 
$
2.6

 
$
0.8

Non-employee directors
 
0.9

 

 
0.9

 

 
 
$
12.7

 
$
4.5

 
$
3.5

 
$
0.8

Percentage of shares granted expected to be distributed:
 
 
 
 
 
 
 
 
Employees
 
95
%
 
91
%
 
94
%
 
89
%
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 nine months of 2017 and 2016 are being recognized over a three-year vesting period. During the first two quarters of 2017 and the first quarter of 2016, there were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a

17


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 performance criteria at September 30, 2017, the participants are estimated to receive 81% of the 2017, 153% of the 2016, and 40% of the 2015 performance based shares. The CFTA performance measurement at September 30, 2017 was assessed to vest at target or 100%. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2017 awards for the first nine months of 2017 was $5.8 million.

NOTE 10 – DERIVATIVES

Commodity Derivatives

We have entered into various types of derivative transactions covering some of our projected natural gas and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of September 30, 2017, our derivative transactions were comprised of the following hedges:

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

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

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

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

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

18



At September 30, 2017, the following derivatives were outstanding:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Oct'17
 
Natural gas – swap
 
70,000 MMBtu/day
 
$3.038
 
IF – NYMEX (HH)
Nov’17 – Dec'17
 
Natural gas – swap
 
60,000 MMBtu/day
 
$2.960
 
IF – NYMEX (HH)
Jan’18 – Dec'18
 
Natural gas – swap
 
20,000 MMBtu/day
 
$3.013
 
IF – NYMEX (HH)
Nov’17 – Dec'17
 
Natural gas – basis swap
 
20,000 MMBtu/day
 
$(0.215)
 
IF – NYMEX (HH)
Jan’18 – Mar'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.208)
 
IF – NYMEX (HH)
Nov’18 – Dec'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.208)
 
IF – NYMEX (HH)
Oct'17
 
Natural gas – collar
 
20,000 MMBtu/day
 
$2.88 - $3.10
 
IF – NYMEX (HH)
Oct'17
 
Natural gas – three-way collar
 
15,000 MMBtu/day
 
$2.50 - $2.00 - $3.32
 
IF – NYMEX (HH)
Nov’17 – Dec'17
 
Natural gas – three-way collar
 
25,000 MMBtu/day
 
$2.90 - $2.30 - $3.59
 
IF – NYMEX (HH)
Jan'18 – Mar'18
 
Natural gas – three-way collar
 
60,000 MMBtu/day
 
$3.29 - $2.63 - $4.07
 
IF – NYMEX (HH)
Apr'18 – Dec'18
 
Natural gas – three-way collar
 
20,000 MMBtu/day
 
$3.00 - $2.50 - $3.51
 
IF – NYMEX (HH)
Oct’17 – Dec'17
 
Crude oil – three-way collar
 
3,750 Bbl/day
 
$49.79 - $39.58 - $60.98
 
WTI – NYMEX
Jan'18 – Dec'18
 
Crude oil – three-way collar
 
2,000 Bbl/day
 
$47.50 - $37.50 - $56.08
 
WTI – NYMEX
Jan'18 – Dec'18
 
Crude oil – swap
 
2,000 Bbl/day
 
$50.140
 
WTI – NYMEX

After September 30, 2017, the following derivative was entered into:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Apr'18 – Oct'18
 
Natural gas – swap
 
10,000 MMBtu/day
 
$2.990
 
IF – NYMEX (HH)
Apr'18 – Sep'18
 
Liquids – swap (1)
 
1,000 Bbl/day
 
$31.164
 
OPIS – Mont Belvieu
_______________________
(1)    Type of liquid involved is propane.

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,
2017
 
December 31,
2016
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative asset
 
$
1,064

 
$

Long-term
 
Non-current derivative asset
 

 
377

Total derivative assets
 
 
 
$
1,064

 
$
377


 
 
 
 
Derivative Liabilities
 
 
 
 
Fair Value
 
 
Balance Sheet Location
 
September 30,
2017
 
December 31,
2016
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative liability
 
$
636

 
$
21,564

Long-term
 
Non-current derivative liability
 
282

 
415

Total derivative liabilities
 
 
 
$
918

 
$
21,979



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 in our Unaudited Condensed Consolidated Balance Sheets.

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the three months ended September 30:
Derivatives Instruments
 
Location of Gain (Loss) Recognized in
Income on Derivative
 
Amount of Gain 
(Loss) Recognized in Income on Derivative
 
 
 
 
2017
 
2016
 
 
 
 
(In thousands)
Commodity derivatives
 
Gain (loss) on derivatives (1)
 
$
(2,614
)
 
$
6,969

Total
 
 
 
$
(2,614
)
 
$
6,969

_______________________
(1)
Amounts settled during the 2017 and 2016 periods include net proceeds of $0.8 million and net payments of $0.5 million, respectively.

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations 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
 
 
 
 
2017
 
2016
 
 
 
 
(In thousands)
Commodity derivatives
 
Gain (loss) on derivatives (1)
 
$
21,019

 
$
(4,774
)
Total
 
 
 
$
21,019

 
$
(4,774
)
_______________________
(1)
Amounts settled during the 2017 and 2016 periods include net payments of $0.7 million and net proceeds of $11.7 million, respectively.

NOTE 11 – FAIR VALUE MEASUREMENTS

The estimated fair value of our available-for-sale securities, reflected on our Unaudited Condensed Consolidated Balance Sheets as Non-current other assets, is based on market quotes. The following is a summary of available-for-sale securities:

 
 
Cost
 
Gross Unrealized Gains
 
Gross Unrealized Losses
 
Estimated Fair Value
 
 
(In thousands)
Equity Securities:
 
 
September 30, 2017
 
$
830

 
$
85

 
$

 
$
915

December 31, 2016
 
$

 
$

 
$

 
$


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

20



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:
 
 
September 30, 2017
 
 
Level 1
 
Level 2
 
Level 3
 
Effect
of Netting
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
 
Assets
 
$

 
$
662

 
$
1,964

 
$
(1,562
)
 
$
1,064

Liabilities
 

 
(2,002
)
 
(478
)
 
1,562

 
(918
)
Total commodity derivatives
 

 
(1,340
)
 
1,486

 

 
146

Equity securities
 
915

 

 

 

 
915

 
 
$
915

 
$
(1,340
)
 
$
1,486

 
$

 
$
1,061

 
 
December 31, 2016
 
 
Level 1
 
Level 2
 
Level 3
 
Effect
of Netting
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
 
Assets
 
$

 
$
878

 
$
43

 
$
(544
)
 
$
377

Liabilities
 

 
(15,358
)
 
(7,165
)
 
544

 
(21,979
)
 
 
$

 
$
(14,480
)
 
$
(7,122
)
 
$

 
$
(21,602
)

All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties and no collateral has been posted as of September 30, 2017.


21


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

Level 1 Fair Value Measurements

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

Level 2 Fair Value Measurements

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

Level 3 Fair Value Measurements

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

The following table is a reconciliation of our level 3 fair value measurements: 
 
 
Net Derivatives
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(In thousands)
Beginning of period
 
$
4,093

 
$
(4,761
)
 
$
(7,122
)
 
$
9,094

Total gains or losses (realized and unrealized):
 
 
 
 
 
 
 
 
Included in earnings (1)
 
(2,015
)
 
3,077

 
9,102

 
(3,257
)
Settlements
 
(592
)
 
(443
)
 
(494
)
 
(7,964
)
End of period
 
$
1,486

 
$
(2,127
)
 
$
1,486

 
$
(2,127
)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period
 
$
(2,607
)
 
$
2,634

 
$
8,608

 
$
(11,221
)
_______________________
(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 September 30, 2017:
Commodity (1)
 
Fair Value
 
Valuation Technique
 
Unobservable Input
 
Range
 
 
(In thousands)
 
 
 
 
 
 
Oil three-way collars
 
$
(9
)
 
Discounted cash flow
 
Forward commodity price curve
 
($3.65) - $5.02
Natural gas collar
 
$
25

 
Discounted cash flow
 
Forward commodity price curve
 
($0.11) - $0.06
Natural gas three-way collars
 
$
1,470

 
Discounted cash flow
 
Forward commodity price curve
 
($0.34) - $0.54
 _______________________
(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.

Our valuation at September 30, 2017 reflected that the risk of non-performance by our counterparties was immaterial.

Fair Value of Other Financial Instruments

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


22


At September 30, 2017, 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 considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at September 30, 2017 and December 31, 2016 was $162.1 million and $160.8 million, respectively. This debt would be classified as Level 2.

The carrying amounts of long-term debt associated with the Notes, net of unamortized discount and debt issuance costs, reported in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 were $641.7 million and $640.1 million, respectively. We estimate the fair value of the Notes using quoted marked prices at September 30, 2017 and December 31, 2016 was $654.6 million and $649.9 million, respectively. The Notes would be classified as Level 2.

Fair Value of Non-Financial Instruments

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

NOTE 12 – COMMITMENTS AND CONTINGENCIES

We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. We also have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately $3.2 million, $0.8 million, $0.4 million, $0.3 million, and less than $0.1 million in twelve month periods beginning October 1, 2017 (and through the end of 2021), respectively. Total rent expense incurred was $6.4 million and $8.7 million for the first nine months of 2017 and 2016, respectively.

In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the four successive twelve month periods beginning October 1, 2017 (and through the end of 2021) are $6.2 million, $6.2 million, $6.2 million, and $5.3 million. Total maintenance and interest remaining related to these leases are $6.3 million and $1.3 million, respectively at September 30, 2017. Annual payments, net of maintenance and interest, average $4.1 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value.

The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal. In any one year, these repurchases are limited to 20% of the units outstanding. We had no repurchases in the first nine months of 2016. We made repurchases of $2,900 during the first nine months of 2017.

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

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

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


23


NOTE 13 – EQUITY

At-the-Market (ATM) Common Stock Program 

On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
 
Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms and conditions of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions that we may impose).
 
We are not obligated to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
 
As of September 30, 2017, we sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million.

Accumulated Other Comprehensive Income

Components of accumulated other comprehensive income were as follows for the three months ended September 30:
 
 
2017
 
2016
 
 
(In thousands)
Unrealized appreciation on securities, before tax
 
$
53

 
$

Tax expense
 
(20
)
 

Unrealized appreciation on securities, net of tax
 
$
33

 
$


Changes in accumulated other comprehensive income by component, net of tax, for the three months ended September 30 are as follows:
 
 
Net Gains on Equity Securities
 
 
2017
 
2016
 
 
(In thousands)
Balance at July 1:
 
$
20

 
$

Unrealized appreciation before reclassifications
 
33

 

Amounts reclassified from accumulated other comprehensive income
 

 

Net current-period other comprehensive income
 
33

 

Balance at September 30:
 
$
53

 
$



24


Components of accumulated other comprehensive income were as follows for the nine months ended September 30:
 
 
2017
 
2016
 
 
(In thousands)
Unrealized appreciation on securities, before tax
 
$
85

 
$

Tax expense
 
(32
)
 

Unrealized appreciation on securities, net of tax
 
$
53

 
$


Changes in accumulated other comprehensive income by component, net of tax, for the nine months ended September 30 are as follows:
 
 
Net Gains on Equity Securities
 
 
2017
 
2016
 
 
(In thousands)
Balance at January 1:
 
$

 
$

Unrealized appreciation before reclassifications
 
53

 

Amounts reclassified from accumulated other comprehensive income
 

 

Net current-period other comprehensive income
 
53

 

Balance at September 30:
 
$
53

 
$


NOTE 14 – INDUSTRY SEGMENT INFORMATION

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

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

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


25


The following tables provide certain information about the operations of each of our segments:
 
 
Three Months Ended September 30, 2017
 
 
Oil and Natural Gas
 
Contract Drilling
 
Mid-stream
 
Other
 
Eliminations
 
Total Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
85,470

 
$

 
$

 
$

 
$

 
$
85,470

Contract drilling
 

 
55,588

 

 

 
(3,969
)
 
51,619

Gas gathering and processing
 

 

 
69,057

 

 
(17,658
)
 
51,399

Total revenues
 
85,470

 
55,588

 
69,057

 

 
(21,627
)
 
188,488

Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
35,082

 

 

 

 
(1,171
)
 
33,911

Contract drilling
 

 
38,115

 

 

 
(3,368
)
 
34,747

Gas gathering and processing
 

 

 
54,602

 

 
(16,486
)
 
38,116

Total operating costs
 
35,082

 
38,115

 
54,602

 

 
(21,025
)
 
106,774

Depreciation, depletion, and amortization
 
26,460

 
15,280

 
10,880

 
1,913

 

 
54,533

Total expenses
 
61,542

 
53,395

 
65,482

 
1,913

 
(21,025
)
 
161,307

Total operating income (loss) (1)
 
23,928

 
2,193

 
3,575

 
(1,913
)
 
(602
)
 
 
General and administrative expense
 

 

 

 
(9,235
)
 

 
(9,235
)
Gain (loss) on disposition of assets
 
(1
)
 
68

 
14

 

 

 
81

Loss on derivatives
 

 

 

 
(2,614
)
 

 
(2,614
)
Interest expense, net
 

 

 

 
(9,944
)
 

 
(9,944
)
Other
 

 

 

 
5

 

 
5

Income (loss) before income taxes
 
$
23,927

 
$
2,261

 
$
3,589

 
$
(23,701
)
 
$
(602
)
 
$
5,474

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

26



 
 
Three Months Ended September 30, 2016
 
 
Oil and Natural Gas
 
Contract Drilling
 
Mid-stream
 
Other
 
Eliminations
 
Total Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
78,854

 
$

 
$

 
$

 
$

 
$
78,854

Contract drilling
 

 
25,819

 

 

 

 
25,819

Gas gathering and processing
 

 

 
63,090

 

 
(14,355
)
 
48,735

Total revenues
 
78,854

 
25,819

 
63,090

 

 
(14,355
)
 
153,408

Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
27,710

 

 

 

 
(1,696
)
 
26,014

Contract drilling
 

 
19,137

 

 

 

 
19,137

Gas gathering and processing
 

 

 
48,397

 

 
(12,659
)
 
35,738

Total operating costs
 
27,710

 
19,137

 
48,397