10-Q 1 unt-2015930x10q.htm 10-Q 10-Q
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, 2015
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.)
 
7130 South Lewis, Suite 1000, Tulsa, Oklahoma
74136
(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 October 23, 2015, 50,414,408 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, such things as:

the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
the amount of wells we plan to drill or rework;
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;
the number of wells our oil and natural gas segment plans to drill during the year; and
our estimates of the amounts of any ceiling test write-downs we may be required to record in future periods.
These statements are based on certain 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;
decreases or increases in demand for and the price for commodities; 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 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,
2015
 
December 31,
2014
 
 
(In thousands except share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
894

 
$
1,049

Accounts receivable, net of allowance for doubtful accounts of $4,758 and $5,039 at September 30, 2015 and at December 31, 2014, respectively
 
101,155

 
189,812

Materials and supplies
 
7,704

 
5,590

Current derivative asset (Note 10)
 
11,461

 
31,139

Current income taxes receivable
 
4,494

 

Current deferred tax asset
 
8,340

 
11,527

Assets held for sale (Note 3)
 
5,321

 

Prepaid expenses and other
 
11,301

 
13,374

Total current assets
 
150,670

 
252,491

Property and equipment:
 
 
 
 
Oil and natural gas properties on the full cost method:
 
 
 
 
Proved properties
 
5,229,832

 
4,990,753

Unproved properties not being amortized
 
454,156

 
485,568

Drilling equipment
 
1,563,433

 
1,620,692

Gas gathering and processing equipment
 
669,512

 
628,689

Saltwater disposal systems
 
60,271

 
56,702

Transportation equipment
 
40,138

 
40,693

Other
 
82,496

 
57,706

 
 
8,099,838

 
7,880,803

Less accumulated depreciation, depletion, amortization, and impairment
 
5,053,204

 
3,747,412

Net property and equipment
 
3,046,634

 
4,133,391

Debt issuance cost
 
9,064

 
10,255

Goodwill
 
62,808

 
62,808

Non-current derivative asset (Note 10)
 
439

 

Other assets
 
14,903

 
14,783

Total assets
 
$
3,284,518

 
$
4,473,728


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,
2015
 
December 31,
2014
 
 
(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
97,503

 
$
218,500

Accrued liabilities (Note 5)
 
68,042

 
70,171

Income taxes payable
 

 
481

Current portion of other long-term liabilities (Note 6)
 
16,806

 
15,019

Total current liabilities
 
182,351

 
304,171

Long-term debt (Note 6)
 
908,234

 
812,163

Other long-term liabilities (Note 6)
 
136,981

 
148,785

Deferred income taxes
 
438,995

 
876,215

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, 50,414,408 and 49,593,812 shares issued as of September 30, 2015 and December 31, 2014, respectively
 
9,831

 
9,732

Capital in excess of par value
 
481,611

 
468,123

Retained earnings
 
1,126,515

 
1,854,539

Total shareholders’ equity
 
1,617,957

 
2,332,394

Total liabilities and shareholders’ equity
 
$
3,284,518

 
$
4,473,728


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,
 
 
2015
 
2014
 
2015
 
2014
 
 
(In thousands except per share amounts)
Revenues:
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
96,619

 
$
188,471

 
$
309,944

 
$
575,176

Contract drilling
 
65,022

 
120,652

 
215,114

 
341,530

Gas gathering and processing
 
50,752

 
91,851

 
156,881

 
277,687

Total revenues
 
212,393

 
400,974

 
681,939

 
1,194,393

Expenses:
 
 
 
 
 
 
 
 
Oil and natural gas:
 
 
 
 
 
 
 
 
Operating costs
 
38,688

 
48,841

 
129,871

 
133,979

Depreciation, depletion, and amortization
 
57,159

 
70,033

 
202,378

 
200,958

Impairment of oil and natural gas properties (Note 2)
 
329,924

 

 
1,141,053

 

Contract drilling:
 
 
 
 
 
 
 
 
Operating costs
 
35,486

 
66,727

 
123,717

 
197,025

Depreciation
 
14,255

 
22,560

 
42,533

 
61,194

Impairment of contract drilling equipment (Note 3)
 

 

 
8,314

 

Gas gathering and processing:
 
 
 
 
 
 
 
 
Operating costs
 
40,314

 
78,558

 
125,081

 
238,166

Depreciation and amortization
 
10,976

 
10,272

 
32,518

 
29,972

General and administrative
 
7,643

 
10,172

 
26,637

 
30,409

(Gain) loss on disposition of assets
 
7,230

 
529

 
6,270

 
(9,092
)
Total operating expenses
 
541,675

 
307,692

 
1,838,372

 
882,611

Income (loss) from operations
 
(329,282
)
 
93,282

 
(1,156,433
)
 
311,782

Other income (expense):
 
 
 
 
 
 
 
 
Interest, net
 
(8,286
)
 
(4,280
)
 
(23,482
)
 
(12,201
)
Gain (loss) on derivatives not designated as hedges (Note 10)
 
8,250

 
19,841

 
12,917

 
(9,234
)
Other
 
16

 
(68
)
 
38

 
3

Total other expense
 
(20
)
 
15,493

 
(10,527
)
 
(21,432
)
Income (loss) before income taxes
 
(329,302
)
 
108,775

 
(1,166,960
)
 
290,350

Income tax expense (benefit):
 
 
 
 
 
 
 
 
Current
 
(2,584
)
 
5,451

 
(1,716
)
 
23,721

Deferred
 
(121,437
)
 
35,802

 
(437,220
)
 
87,802

Total income taxes
 
(124,021
)
 
41,253

 
(438,936
)
 
111,523

Net income (loss)
 
$
(205,281
)
 
$
67,522

 
$
(728,024
)
 
$
178,827

Net income (loss) per common share:
 
 
 
 
 
 
 
 
Basic
 
$
(4.18
)
 
$
1.39

 
$
(14.83
)
 
$
3.68

Diluted
 
$
(4.18
)
 
$
1.37

 
$
(14.83
)
 
$
3.65


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


5


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
Nine Months Ended
 
 
September 30,
 
 
2015
 
2014
 
 
(In thousands)
OPERATING ACTIVITIES:
 
 
 
 
Net income (loss)
 
$
(728,024
)
 
$
178,827

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, and amortization
 
279,739

 
294,412

Impairments (Notes 2 and 3)
 
1,149,367

 

(Gain) loss on derivatives (Note 10)
 
(12,917
)
 
9,234

Cash receipts (payments) on derivatives settled (Note 10)
 
32,156

 
(18,984
)
Deferred tax expense (benefit)
 
(437,220
)
 
87,802

(Gain) loss on disposition of assets
 
6,270

 
(9,092
)
Employee stock compensation plans
 
12,514

 
17,780

Other, net
 
1,834

 
5,156

Changes in operating assets and liabilities increasing (decreasing) cash:
 
 
 
 
Accounts receivable
 
84,098

 
(47,704
)
Accounts payable
 
(4,432
)
 
1,708

Material and supplies
 
(2,114
)
 
2,222

Accrued liabilities
 
(363
)
 
28,596

Other, net
 
574

 
(430
)
Net cash provided by operating activities
 
381,482

 
549,527

INVESTING ACTIVITIES:
 
 
 
 
Capital expenditures
 
(484,028
)
 
(686,405
)
Proceeds from disposition of assets
 
9,838

 
49,341

Other
 

 
303

Net cash used in investing activities
 
(474,190
)
 
(636,761
)
FINANCING ACTIVITIES:
 
 
 
 
Borrowings under credit agreement
 
484,600

 
395,700

Payments under credit agreement
 
(388,900
)
 
(364,900
)
Payments on capitalized leases
 
(2,648
)
 
(1,505
)
Proceeds from exercise of stock options
 
4

 
926

Book overdrafts
 
(503
)
 
39,315

Net cash provided by financing activities
 
92,553

 
69,536

Net decrease in cash and cash equivalents
 
(155
)
 
(17,698
)
Cash and cash equivalents, beginning of period
 
1,049

 
18,593

Cash and cash equivalents, end of period
 
$
894

 
$
895

Supplemental disclosure of cash flow information:
 
 
 
 
Cash paid during the year for:
 
 
 
 
Interest paid (net of capitalized)
 
12,691

 
(1,340
)
Income taxes
 
3,277

 
16,000

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
 
116,062

 
(42,651
)
Non-cash reductions to oil and natural gas properties related to asset retirement obligations
 
8,558

 
40,516

Non-cash additions to property, plant, and equipment acquired under capital leases
 

 
(28,202
)

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

6


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 24, 2015, for the year ended December 31, 2014.

In our management's opinion, 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 September 30, 2015 and December 31, 2014;
Statements of Operations for the three and nine months ended September 30, 2015 and 2014; and
Statements of Cash Flows for the nine months ended September 30, 2015 and 2014.

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 nine months ended September 30, 2015 and 2014 are not necessarily indicative of the results to be realized for the full year of 2015, or that we realized for the full year of 2014.

We reclassified certain amounts in the accompanying unaudited condensed consolidated financial statements for prior periods to conform to current year presentation. Certain financial statement captions were also expanded or combined with no impact to consolidated net income (loss) or shareholders' equity.

Regarding the unaudited financial information for the three and nine month periods ended September 30, 2015 and 2014, our auditors, PricewaterhouseCoopers LLP, reported that it applied limited procedures under professional standards in reviewing that information. Its separate report dated November 3, 2015, which is included in this report, states it did not audit nor did it express an opinion on that unaudited financial information. The reliance placed on its report should be restricted in light of the limited review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 (Act) for its report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

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. We are required to take the charge 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 and second quarter quarter of 2015, the 12-month average commodity prices decreased significantly, resulting in non-cash ceiling test write-downs of $400.6 million pre-tax ($249.4 million, net of tax) and $410.5 million pre-tax ($255.6 million, net of tax), respectively.


7



During the third quarter of 2015, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of $329.9 million pre-tax ($205.4 million, net of tax).

NOTE 3 – DIVESTITURES

Oil and Natural Gas

We sold non-core oil and natural gas assets, net of related expenses, for $0.2 million during the first nine months of 2015, compared to $18.5 million during the first nine months of 2014. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

Contract Drilling

In December 2014, we removed from service 31 drilling rigs, some older top drives, and certain drill pipe no longer marketable under the current environment and based on estimated market value from third party assessments (Level 3 fair value measurement), we recorded a write-down of approximately $74.3 million pre-tax. During the first quarter of 2015, we sold one of these drilling rigs to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $0.3 million net book value of the drilling rig resulting in a gain of $7,900. During the second quarter, we recorded an additional write-down on the remaining drilling rigs and other equipment of approximately $8.3 million pre-tax based on the estimated market value from similar auctions. During the third quarter we sold the remaining 30 drilling rigs and most of the equipment in an auction. The proceeds from the sale of those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax. The equipment that was not sold at the auction will be sold within the next twelve months and remain classified as assets held for sale. The net book value of those assets is $5.3 million.

During the first quarter of 2014, we sold four idle 3,000 horsepower drilling rigs to an unaffiliated third-party. The proceeds of this sale, less sales costs, exceeded the $16.3 million net book value of the drilling rigs, both in the aggregate and for each drilling rig, resulting in a gain of $9.6 million.

NOTE 4 – EARNINGS PER SHARE

Information related to the calculation of earnings per share follows:
 
 
Income (Loss)
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
 
(In thousands except per share amounts)
For the three months ended September 30, 2015
 
 
 
 
 
 
Basic earnings (loss) per common share
 
$
(205,281
)
 
49,155

 
$
(4.18
)
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)
 

 

 

Diluted earnings (loss) per common share
 
$
(205,281
)
 
49,155

 
$
(4.18
)
For the three months ended September 30, 2014
 
 
 
 
 
 
Basic earnings per common share
 
$
67,522

 
48,650

 
$
1.39

Effect of dilutive stock options, restricted stock, and SARs
 

 
527

 
(0.02
)
Diluted earnings per common share
 
$
67,522

 
49,177

 
$
1.37



8


Due to the net loss for the three months ended September 30, 2015, approximately 296,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and were excluded from the earnings per share 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,
 
 
2015
 
2014
Stock options and SARs
 
261,270

 
24,500

Average exercise price
 
$
50.34

 
$
73.26



 
 
Income (Loss)
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
 
(In thousands except per share amounts)
For the nine months ended September 30, 2015
 
 
 
 
 
 
Basic earnings (loss) per common share
 
$
(728,024
)
 
49,094

 
$
(14.83
)
Effect of dilutive stock options, restricted stock, and SARs
 

 

 

Diluted earnings (loss) per common share
 
$
(728,024
)
 
49,094

 
$
(14.83
)
For the nine months ended September 30, 2014
 
 
 
 
 
 
Basic earnings per common share
 
$
178,827

 
48,596

 
$
3.68

Effect of dilutive stock options, restricted stock, and SARs
 

 
458

 
(0.03
)
Diluted earnings per common share
 
$
178,827

 
49,054

 
$
3.65


Due to the net loss for the nine months ended September 30, 2015, approximately 204,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and were excluded from the earnings per share 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,
 
 
2015
 
2014
Stock options and SARs
 
261,270

 
49,000

Average exercise price
 
$
50.34

 
$
67.83



9


NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:
 
 
September 30,
2015
 
December 31,
2014
 
 
(In thousands)
Lease operating expenses
 
$
19,923

 
$
20,709

Interest
 
17,036

 
6,654

Employee costs
 
12,300

 
31,451

Taxes
 
11,984

 
3,284

Third-party credits
 
2,854

 
2,825

Other
 
3,945

 
5,248

Total accrued liabilities
 
$
68,042

 
$
70,171

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

Long-Term Debt

As of the dates in the table, our long-term debt consisted of the following:
 
 
September 30,
2015
 
December 31,
2014
 
 
(In thousands)
Credit agreement with an average interest rate of 4.0% and 2.9% at September 30, 2015 and December 31, 2014, respectively
 
$
261,700

 
$
166,000

6.625% senior subordinated notes due 2021, net of unamortized discount of $3.5 million and $3.8 million at September 30, 2015 and December 31, 2014, respectively
 
646,534

 
646,163

Total long-term debt
 
$
908,234

 
$
812,163


Credit Agreement. On April 10, 2015, we amended our Senior Credit Agreement (credit agreement) to extend the maturity date from September 13, 2016 to April 10, 2020. The amount we can borrow is the lesser of the amount we elect (from time to time) as the commitment amount or the value of the borrowing base as determined by the lenders (currently $550.0 million), but in either event not to exceed the maximum credit agreement amount of $900.0 million. Our current elected commitment amount is $500.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% 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. To date, for this new amendment, we paid $2.6 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement.

The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. Effective with the October 2015 redetermination, the lenders under our credit agreement decreased our borrowing base from $725.0 million to $550.0 million. 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 1.75% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the 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, 2015, the outstanding borrowings under the credit agreement were $261.7 million.


10


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 (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; and
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, 2015, 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). 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 connection with the issuance of the Notes we incurred $14.7 million of fees 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 and providing for issuing the Notes. The Guarantors are all 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 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.

Before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. 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 September 30, 2015.


11


Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
 
 
September 30,
2015
 
December 31,
2014
 
 
(In thousands)
Asset retirement obligation (ARO) liability
 
$
94,608

 
$
100,567

Capital lease obligations
 
23,332

 
25,876

Workers’ compensation
 
16,800

 
17,997

Separation benefit plans
 
10,560

 
11,276

Deferred compensation plan
 
4,454

 
4,055

Gas balancing liability
 
3,623

 
3,623

Other
 
410

 
410

 
 
153,787

 
163,804

Less current portion
 
16,806

 
15,019

Total other long-term liabilities
 
$
136,981

 
$
148,785


Estimated annual principal payments under the terms of debt and other long-term liabilities during each of the five successive twelve month periods beginning October 1, 2015 (and through 2020) are $16.8 million, $39.2 million, $9.1 million, $8.3 million, and $271.0 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 $3.5 million portion of our capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $19.8 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 2015. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining at September 30, 2015 related to these leases are $9.9 million and $2.9 million, respectively. Annual payments, net of maintenance and interest, average $3.8 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time.

Future payments required under the capital leases at September 30, 2015:
 
 
Amount
Ending September 30,
 
(In thousands)
2016
 
$
6,168

2017
 
6,168

2018
 
6,168

2019
 
6,168

2020
 
6,168

2021 and thereafter
 
5,311

Total future payments
 
36,151

Less payments related to:
 
 
Maintenance
 
9,891

Interest
 
2,928

Present value of future minimum payments
 
$
23,332



12


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:
 
 
Nine Months Ended
 
 
September 30,
 
 
2015
 
2014
 
 
(In thousands)
ARO liability, January 1:
 
$
100,567

 
$
133,657

Accretion of discount
 
2,599

 
3,538

Liability incurred
 
6,505

 
2,889

Liability settled
 
(1,933
)
 
(3,936
)
Liability sold
 
(249
)
 
(1,206
)
Revision of estimates (1)
 
(12,881
)

(38,263
)
ARO liability, September 30:
 
94,608

 
96,679

Less current portion
 
3,481

 
2,718

Total long-term ARO
 
$
91,127

 
$
93,961

_______________________ 
(1)
Plugging liability estimates were revised in both 2015 and 2014 to account for changes 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

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 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. 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. Early adoption of the amendments is permitted for financial statements that have not been previously issued. 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 do not expect the adoption of this guidance will have a material impact on our financial statements.

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. 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.


13


NOTE 9 – STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(In millions)
Recognized stock compensation expense
 
$
2.1

 
$
4.4

 
$
11.2

 
$
12.7

Capitalized stock compensation cost for our oil and natural gas properties
 
0.7

 
0.9

 
2.6

 
2.7

Tax benefit on stock based compensation
 
0.8

 
1.7

 
4.2

 
4.9


The remaining unrecognized compensation cost related to unvested awards at September 30, 2015 is approximately $19.1 million, of which $3.4 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.8 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.

We did not grant any SARs or stock options during either of the three or nine month periods ending September 30, 2015 and 2014. The following table shows the fair value of restricted stock awards granted to employees and non-employee directors during the nine months ended September 30, 2015 and 2014. There were no shares granted during the three months ended September 30, 2015 and 2014.
 
 
Nine Months Ended
 
 
September 30,
 
 
2015
 
2014
Shares granted:
 
 
 
 
Employees
 
724,442

 
438,342

Non employee directors
 
25,848

 
13,768

 
 
750,290

 
452,110

Estimated fair value (in millions):
 
 
 
 
Employees
 
$
23.6

 
$
22.4

Non employee directors
 
0.9

 
0.9

 
 
$
24.5

 
$
23.3

Percentage of shares granted expected to be distributed:
 
 
 
 
Employees
 
75
%
 
90
%
Non employee directors
 
100
%
 
100
%

The restricted stock awards granted during the first nine months of 2015 and 2014 are being recognized over a three year vesting period, except for a portion of those awards made to certain executive officers. As to those executive officers, 50% of the shares granted, or 148,081 shares in 2015, 40% of the shares granted, or 71,674 shares in 2014, and 30% of the shares granted, or 57,405 shares in 2013, (the performance shares), will cliff vest in the first half of 2018, 2017, and 2016, respectively. The actual number of performance shares that vest in 2016, 2017, and 2018 will be based on the company’s achievement of certain stock performance measures at the end of the term, and will range from 0% to 150% of the restricted shares granted as performance shares. Based on a probability assessment of the selected performance criteria at September 30, 2015, the participants are estimated to receive none of the 2015, 67% of the 2014, and 11% of the 2013 performance based shares. Based on this assessment, we reduced our accrual for total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties by $3.0 million. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2015 awards for the first nine months of 2015 was $6.8 million.


14


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, 2015, 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.

Collars. A collar contains a fixed floor price (long put) and a ceiling price (short 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. The change in fair value on all commodity derivatives is reflected in the statement of operations and not in accumulated other comprehensive income (OCI).

At September 30, 2015, the following non-designated hedges were outstanding:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Oct’15 – Dec’15
 
Crude oil – swap
 
1,000 Bbl/day
 
$95.00
 
WTI – NYMEX
Oct’15 – Dec’15
 
Crude oil – collar
 
2,000 Bbl/day
 
$58.00 - $64.40
 
WTI – NYMEX
Oct’15 – Dec’15
 
Natural gas – swap
 
40,000 MMBtu/day
 
$3.98
 
NYMEX (HH)
Jan'16 - Dec'16
 
Natural gas – swap
 
10,000 MMBtu/day
 
$3.25
 
NYMEX (HH)
Nov'15 - Dec'16
 
Natural gas – three-way collar
 
13,500 MMBtu/day
 
$2.70 - $2.20 - $3.26
 
NYMEX (HH)

After September 30, 2015, the following non-designated hedges were entered into:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Jan'16 - Jun'16
 
Crude oil – collar
 
700 Bbl/day
 
$44.00 - $54.00
 
WTI – NYMEX
Jan'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'16 - Dec'16
 
Natural gas – collar
 
27,000 MMBtu/day
 
$2.50 - $3.11
 
NYMEX (HH)
_______________________
(1)
We pay our counterparty a premium, which can be and is being deferred until settlement.


15


The following table presents 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,
2015
 
December 31,
2014
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative asset
 
$
11,461

 
$
31,139

   Long-term
 
Non-current derivative asset
 
439

 

Total derivative assets
 
 
 
$
11,900

 
$
31,139


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.

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 not designated as hedges in our Unaudited Condensed Consolidated Statements of Operations.

Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations (derivatives not designated as hedging instruments) for the three months ended September 30:
Derivatives Not Designated as
Hedging Instruments
 
Location of Gain or (Loss) Recognized in
Income on Derivative
 
Amount of Gain or (Loss) Recognized in Income on Derivative
 
 
 
 
2015
 
2014
 
 
 
 
(In thousands)
Commodity derivatives
 
Gain on derivatives not designated as
    hedges(1)
 
$
8,250

 
$
19,841

Total
 
 
 
$
8,250

 
$
19,841

_______________________
(1)
Amounts settled during the 2015 and 2014 periods include a gain of $11.1 million and a loss of $1.0 million, respectively.

Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations (derivatives not designated as hedging instruments) for the nine months ended September 30:
Derivatives Not Designated as
Hedging Instruments
 
Location of Gain or (Loss) Recognized in
Income on Derivative
 
Amount of Gain or (Loss) Recognized in Income on Derivative
 
 
 
 
2015
 
2014
 
 
 
 
(In thousands)
Commodity derivatives
 
Gain (loss) on derivatives not designated as hedges (1)
 
$
12,917

 
$
(9,234
)
Total
 
 
 
$
12,917

 
$
(9,234
)
_______________________
(1)
Amounts settled during the 2015 and 2014 periods include a gain of $32.2 million and a loss of $19.0 million, respectively.


16


NOTE 11 – FAIR VALUE MEASUREMENTS

Fair value is defined as the amount received from the sale of an asset or paid for transferring a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value. The highest priority is given to Level 1 and the lowest priority is 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. Inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.

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

The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments. We corroborate these inputs based on recent transactions and broker quotes and compare the fair value with actual settlements.

The following tables set forth our recurring fair value measurements:
 
 
September 30, 2015
 
 
Level 2
 
Level 3
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
Assets
 
$
9,418

 
$
2,482

 
$
11,900

Liabilities
 

 

 

 
 
$
9,418

 
$
2,482

 
$
11,900

 
 
December 31, 2014
 
 
Level 2
 
Level 3
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
Assets
 
$
27,784

 
$
3,355

 
$
31,139

Liabilities
 

 

 

 
 
$
27,784

 
$
3,355

 
$
31,139


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 cash collateral with our counterparties.

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.

17



Level 3 Fair Value Measurements

Commodity Derivatives. The fair values of our crude oil collars and natural gas 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: 
 
 
Commodity Derivatives
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(In thousands)
Beginning of period
 
$
207

 
$
(6,081
)
 
$
3,355

 
$
(2,595
)
Total gains or losses (realized and unrealized):
 
 
 
 
 
 
 
 
Included in earnings (1)
 
4,436

 
5,785

 
5,324

 
(2,043
)
Settlements
 
(2,161
)
 
887

 
(6,197
)
 
5,229

End of period
 
$
2,482

 
$
591

 
$
2,482

 
$
591

Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period
 
$
2,275

 
$
6,672

 
$
(873
)
 
$
3,186

_______________________
(1)
Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives not designated as hedges.

The following table provides quantitative information about our Level 3 unobservable inputs at September 30, 2015:
Commodity (1)
 
Fair Value
 
Valuation Technique
 
Unobservable Input
 
Range
 
 
(In thousands)
 
 
 
 
 
 
Oil collar
 
$
2,300

 
Discounted cash flow
 
Forward commodity price curve
 
$0.01 - $12.80
Natural gas three-way collar
 
182

 
Discounted cash flow
 
Forward commodity price curve
 
$0.01 - $0.30
 _______________________
(1)
The commodity contracts detailed in this category include a non-exchange-traded crude oil collar and a natural gas three-way collar 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 September 30, 2015, we determined that 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 under 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 these estimates. Using different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

At September 30, 2015, 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 has historically approximated its fair value and at September 30, 2015 was $261.7 million. This debt would be classified as Level 2.

The carrying amounts of long-term debt, net of unamortized discount, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014 were $646.5 million and

18


$646.2 million, respectively. We estimated the fair value of these Notes using quoted marked prices at September 30, 2015 and December 31, 2014 which were $528.1 million and $605.5 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:
 
Oil and natural gas,
Contract drilling, and
Mid-stream

The 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. Our oil and natural gas properties outside the United States are not significant.

19



The following table provides certain information about the operations of each of our segments:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
96,619

 
$
188,471

 
$
309,944

 
$
575,176

 
 
 
 
 
 
 
 
 
Contract drilling
 
68,426

 
147,866

 
234,177

 
407,905

Elimination of inter-segment revenue
 
(3,404
)
 
(27,214
)
 
(19,063
)
 
(66,375
)
Contract drilling net of inter-segment revenue
 
65,022

 
120,652

 
215,114

 
341,530

 
 
 
 
 
 
 
 
 
Gas gathering and processing
 
66,836

 
113,467

 
209,803

 
350,181

Elimination of inter-segment revenue
 
(16,084
)
 
(21,616
)
 
(52,922
)
 
(72,494
)
Gas gathering and processing net of inter-segment revenue
 
50,752

 
91,851

 
156,881

 
277,687

 
 
 
 
 
 
 
 
 
Total revenues
 
$
212,393

 
$
400,974

 
$
681,939

 
$
1,194,393

Operating income (loss):
 

 

 
 
 
 
Oil and natural gas
 
$
(329,152
)
 
$
69,597

 
$
(1,163,358
)
 
$
240,239

Contract drilling
 
15,281

 
31,365

 
40,550

 
83,311

Gas gathering and processing
 
(538
)
 
3,021

 
(718
)
 
9,549

Total operating income (loss) (1)
 
(314,409
)
 
103,983

 
(1,123,526
)
 
333,099

General and administrative
 
(7,643
)
 
(10,172
)
 
(26,637
)
 
(30,409
)
Gain (loss) on disposition of assets
 
(7,230
)
 
(529
)
 
(6,270
)
 
9,092

Gain (loss) on derivatives not designated as hedges
 
8,250

 
19,841

 
12,917

 
(9,234
)
Interest expense, net
 
(8,286
)
 
(4,280
)
 
(23,482
)
 
(12,201
)
Other
 
16

 
(68
)
 
38

 
3

Income (loss) before income taxes
 
$
(329,302
)
 
$
108,775

 
$
(1,166,960
)
 
$
290,350

_______________________
(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, gain (loss) on non-designated hedges, interest expense, other income (loss), or income taxes.


20


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Unit Corporation

We have reviewed the accompanying unaudited condensed consolidated balance sheet of Unit Corporation and its subsidiaries as of September 30, 2015, and the related unaudited condensed consolidated statements of operations for the three month and nine month periods ended September 30, 2015 and 2014 and the unaudited condensed consolidated statement of cash flows for the nine month periods ended September 30, 2015 and 2014. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying unaudited condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2014, and the related consolidated statements of operations, shareholder’s equity and of cash flows for the year then ended (not presented herein), and in our report dated February 24, 2015, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2014, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

 
/s/ PricewaterhouseCoopers LLP
 
Tulsa, Oklahoma
November 3, 2015


21


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis (MD&A) provides an understanding of our operating results and financial condition by focusing on changes in certain key measures from year to year. We have organized MD&A into the following sections: 

General;
Business Outlook;
Executive Summary;
Financial Condition and Liquidity;
New Accounting Pronouncements; and
Results of Operations.

Please read the following discussion and our unaudited condensed consolidated financial statements and related notes with the information in our most recent Annual Report on Form 10-K.

Unless otherwise indicated or required by the content, when used in this report the terms “company,” “Unit,” “us,” “our,” “we,” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries.

General

We operate, manage, and analyze our results of operations through our three principal business segments: 

Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires, and produces oil and natural gas properties for our own account.
Contract Drilling – carried out by our subsidiary Unit Drilling Company and its subsidiaries. This segment contracts to drill onshore oil and natural gas wells for others and for our own account.
Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account.

Business Outlook

As discussed in other parts of this report, the success of our consolidated business, and that of each of our three operating segments, depends, to a large extent, on: the prices we receive for and the amount of our oil, NGLs, and natural gas production; the demand for oil, NGLs, and natural gas; and, the demand for our drilling rigs which influences the amounts we can charge for those drilling rigs. Although all of our current operations are within the United States, events outside the United States can affect us and our industry.

Both within the United States and the world, deteriorating commodity prices have brought about significant and immediate changes affecting our industry and us. The decline in commodity prices has caused us (and other oil and gas companies) to reduce our level of drilling activity and spending. When drilling activity and spending decline for any sustained period of time the number of our drilling rigs working and the rates we charge for them also decline. In addition, lower commodity prices for any sustained period of time could affect the liquidity condition of some of our industry partners and customers, which might limit their ability to meet their financial obligations to us.

It is uncertain how long the current depressed prices for oil and natural gas products will continue. As noted elsewhere in this report, commodity prices are subject to several factors most of which are beyond our control.

The impact on our business and financial results because of the reduction in oil and NGLs (and to a lesser extent natural gas) prices is uncertain in the long term, but in the short term, it has had several consequences for us, including:

In March 2015, we incurred a non-cash ceiling test write-down of our oil and natural gas properties of $400.6 million pre-tax ($249.4 million net of tax), in June 2015, we incurred a non-cash ceiling test write-down of our oil and natural gas properties of $410.5 million pre-tax ($255.6 million net of tax), and in September 2015, we incurred

22


a non-cash ceiling test write-down of our oil and natural gas properties of $329.9 million pre-tax ($205.4 million net of tax). We expect to incur a non-cash ceiling test write-down in the fourth quarter of 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward reserve revisions, reserve additions, and tax attributes. Subject to these numerous factors and inherent limitations, holding these factors constant and only adjusting the 12-month average price to an estimated fourth quarter ending average (holding October 2015 prices constant for the remaining two months of 2015), we currently anticipate that we could recognize an impairment in the fourth quarter of 2015 of approximately $260 million pre-tax. After the end of the year, the impact of the significantly higher commodity prices from 2014 used in the ceiling test 12-month average price calculation will lessen as those prices will no longer be used in the ceiling test.
The majority of our drilling rig customers have significantly reduced their drilling budgets for 2015, resulting in a significant reduction in the average utilization of our drilling rig fleet. At December 31, 2014, we had 75 rigs operating, at September 30, 2015, this number was 29.
Due to the low NGLs prices, we are operating our processing facilities in full ethane rejection mode which reduces the amount of liquids sold. As long as NGLs prices continue to be depressed, we expect to continue operating in full ethane rejection mode. As low commodity prices continue, we expect the reductions in drilling activity around our systems will reduce the number of new wells available to connect to our systems and result in lower processed volumes as production from wells previously connected naturally decline.
Effective with the October 2015 redetermination, the lenders of our credit agreement decreased our borrowing base from $725.0 million to $550.0 million. This new amount is above the $500.0 million commitment we have elected under the credit agreement.

Executive Summary

Oil and Natural Gas

Third quarter 2015 production from our oil and natural gas segment was 5,053,000 barrels of oil equivalent (Boe) which was essentially unchanged from the second quarter of 2015 and an increase of 10% over the third quarter of 2014. The increases over the third quarter of 2014 were primarily from production associated with new wells drilled in 2014 and 2015.

Third quarter 2015 oil and natural gas revenues decreased 10% from the second quarter of 2015 and decreased 49% from third quarter of 2014, respectively. The respective decreases were due primarily to lower oil, NGLs, and natural gas prices.

Our oil prices for the third quarter of 2015 decreased 8% from the second quarter of 2015 and decreased 44% from the third quarter of 2014. Our NGLs prices decreased 27% and 71% from the second quarter of 2015 and third quarter of 2014, respectively. Our natural gas prices were essentially unchanged from the second quarter of 2015 and decreased 28% from the third quarter of 2014.

Operating cost per Boe produced for the third quarter of 2015 decreased 16% from the second quarter of 2015 and decreased 28% from the third quarter of 2014. Costs decreased between the third and second quarters of 2015 primarily due to lower lease operating expenses, workover expenses, and gross production taxes from lower sales revenue and more gross production tax credits. The decrease from the third quarter of 2014 was primarily due to lower gross production tax from lower sales revenue, lower lease operating expense, and lower general and administrative expenses partially offset by higher saltwater disposal expense.


23


For the remainder of 2015, we have derivative contracts covering approximately 3,000 Bbls per day of oil production. For the month of October, we have hedged approximately 40,000 MMBtu per day of natural gas production and for November and December, we have hedged approximately 53,500 MMBtu per day of natural gas production. For 2016, we have hedged approximately 1,400 Bbls per day of oil production and 50,500 MMbtu per day of natural gas production. We currently have the following outstanding hedges by contract type:

Swaps:
Commodity
 
Term
 
Volume
 
Weighted Average Fixed Price
Crude oil
 
Oct'15 - Dec'15
 
1,000 Bbl/day
 
$
95.00

Natural gas
 
Oct'15 - Dec'15
 
40,000 MMBtu/day
 
$
3.98

Natural gas
 
Jan'16 - Dec'16
 
10,000 MMBtu/day
 
$
3.25


Collars:
Commodity
 
Term
 
Volume
 
Weighted Average Floor Price
 
Weighted Average Ceiling Price
Crude oil
 
Oct'15 - Dec'15
 
2,000 Bbl/day
 
$
58.00

 
$
64.40

Crude oil
 
Jan'16 - Jun'16
 
700 Bbl/day
 
$
44.00

 
$
54.00

Natural gas
 
Jan'16 - Dec'16
 
27,000 MMBtu/day
 
$
2.50

 
$
3.11


Three-Way Collars:
Commodity
 
Term
 
Volume
 
Weighted Average Floor Price
 
Weighted Average Subfloor Price
 
Weighted Average Ceiling Price
Crude oil
 
Jan'16 - Dec'16
 
700 Bbl/day
 
$
46.50

 
$
35.00

 
$
57.00

Crude oil(1)
 
Jul'16 - Dec'16
 
700 Bbl/day
 
$
47.50

 
$
35.00

 
$
63.50

Natural gas
 
Nov'15 - Dec'16
 
13,500 MMBtu/day
 
$
2.70

 
$
2.20

 
$
3.26

_______________________
(1)
We pay our counterparty a premium, which can be and is being deferred until settlement.

As of September 30, 2015, we completed drilling 42 gross wells (28.29 net wells). For all of 2015, we plan to participate in the drilling of approximately 50-60 gross wells. Excluding acquisitions and ARO liability, our estimated 2015 capital expenditures for this segment are $278.5 million. Our current 2015 production guidance is approximately 19.4 to 19.8 MMBoe, an increase of 6% to 8% over 2014, although actual results continue to be subject to many factors.

Contract Drilling

The average number of drilling rigs we operated for the third quarter of 2015 was 31.2 compared to 30.7 and 79.1 in the second quarter of 2015 and the third quarter of 2014, respectively. Late in the fourth quarter of 2014, the number of our drilling rigs operating started to decline and has continued to decline throughout the first six months of 2015 due to lower commodity prices and operators reducing their drilling budgets. As of September 30, 2015, 29 drilling rigs were operating.

Revenue for the third quarter of 2015 increased 18% over the second quarter of 2015 and decreased 46% from the third quarter of 2014. The increase over second quarter of 2015 was primarily due to early contract termination revenue. The third quarter of 2015 included early contract termination revenue of $11.4 million compared to $1.6 million in the second quarter of 2015. There was no early termination revenue during the third quarter of 2014. The decrease from the third quarter of 2014 was primarily due to fewer rigs operating.

Dayrates for the third quarter of 2015 averaged $18,800, a 5% and 6% decrease from the second quarter of 2015 and third quarter of 2014, respectively. The decreases were due to downward pressure on dayrates with lower demand.

Operating costs for the third quarter of 2015 decreased 3% and 47% from the second quarter of 2015 and the third quarter of 2014, respectively. The decreases from the second quarter were from reduced indirect, workers' compensation, and general and administrative expenses while the decreases from the quarter of 2014 were due primarily to fewer rigs operating.

24



Low commodity prices continue to curtail our customer drilling budgets and demand for our drilling rigs. As a result, we are experiencing reduced drilling rig utilization. Almost all of our working drilling rigs in 2015 have been drilling horizontal or directional wells. Our drilling rig fleet consists of drilling rigs capable of meeting our customers' demands whether it be for oil, natural gas, or NGLs and whether it be for shallow, deep, vertical, or horizontal type drilling. Current and future demand for drilling rigs and the availability of drilling rigs to meet that demand will affect our future dayrates.

As of September 30, 2015, we had 29 drilling rigs operating. Of those, 18 are on spot market contracts and 11 are on term drilling contracts, with original terms ranging from six months to two years. One term contract is up for renewal in the fourth quarter of 2015, seven are up for renewal in 2016, and three are up for renewal in 2017. Term contracts may contain a fixed rate for the duration of the contract or provide for rate adjustments within a specific range from the existing rate. Some operators who had signed term contracts have opted to release the drilling rig and pay an early termination penalty for the remaining term of the contract. During the third quarter, we were notified of a customer's intent to terminate two of our BOSS drilling rigs term contracts. Since then, the customer has decided to keep one of the BOSS drilling rigs through its remaining term and the other has been contracted by another third party operator. During the first nine months of 2015, we recorded $25.7 million in early termination fees.

We have completed our current new BOSS drilling rig program for 2015. Eight new BOSS drilling rigs have been placed into service. Some of the long lead time components for three additional BOSS drilling rigs were ordered during 2014 and will be delivered in the next twelve months. Currently, we do not have any contracts to build new BOSS drilling rigs. Our estimated 2015 capital expenditures for this segment are $86.1 million.

Mid-Stream

Third quarter 2015 liquids sold per day decreased 3% from the second quarter of 2015 and decreased 25% from the third quarter of 2014. The decrease from the second quarter of 2015 was due to more effectively operating our processing facilities in full ethane rejection mode. The decrease from the third quarter of 2014 was due to operating in ethane ejection mode in 2015. For the third quarter of 2015, gas processed per day were essentially unchanged from the second quarter of 2015 and increased 10% over the third quarter of 2014. The increase over the third quarter of 2014 was primarily due to connecting new wells to both existing and newly constructed systems to replace production declines from wells already connected. For the third quarter of 2015, gas gathered per day decreased 2% from the second quarter of 2015 due to general declines in wells and increased 12% over the third quarter of 2014 due to additional wells added to our systems.

NGLs prices in the third quarter of 2015 decreased 12% from the prices received in the second quarter of 2015 and decreased 53% from the prices received in the third quarter of 2014. Because certain contracts used by our mid-stream segment for NGLs transactions are percent of proceeds (POP) contracts–under which we receive a share of the proceeds from the sale of the NGLs–our revenues from those POP contracts fluctuate based on the price of NGLs.

Operating costs for the third quarter of 2015 decreased 1% from the second quarter of 2015 and decreased 49% from the third quarter of 2014 due primarily to lower gas purchase prices.

With the completion of the connection of the Buffalo Wallow gathering system to our Hemphill County, Texas processing facility in January of this year, we are currently processing all the Buffalo Wallow production at our Hemphill facility. The average throughput volume for the third quarter of 2015 at this facility was approximately 88 MMcf per day which includes the Buffalo Wallow production. The Hemphill facility has total processing capacity of approximately 135 MMcf per day.

During the third quarter of 2015, we connected six new wells to our Bellmon system in north central Oklahoma. For the year through September, we have connected a total of 38 new wells to this system. Total processing capacity at this facility is 90 MMcf per day from two cryogenic processing plant skids. During the third quarter of 2015, we had an average throughput volume of 41 MMcf per day at this system. Upgrades are being completed that will allow us to begin gathering and processing additional production we believe will be available in the near future.  

At our Segno gathering facility located in southeast Texas, we continue to work on several upgrade projects to increase our gathering capacity up 120 MMcf per day. Most of these projects have been completed but we are continuing to work on looping a section of pipeline that will allow us to move additional volume and reduce pipeline pressure. The majority of the right of way for this line looping project has been acquired and we expect to begin pipeline construction in the fourth quarter of 2015. This project is expected to be completed and operational by the end of 2015. We connected four new wells to this gathering system in the third quarter of 2015 and have connected a total of 11 wells to this system since the first of the year. The average daily throughput volume for the third quarter is approximately 75 MMcf per day.

25



In the Appalachian region, we are continuing to work on the expansion of our Pittsburgh Mills gathering system. This expansion project extends our system into Butler County, Pennsylvania and will provide us another outlet for our gas. We have completed the seven-mile pipeline construction and are currently gathering gas from new well pads in the area. We are completing the construction of the compressor station and it is expected to be operational in the fourth quarter of this year. This expansion into Butler County, Pennsylvania allows us the ability to connect additional well pads which are scheduled to be connected to our system in the first half of 2016. 

Also in the Appalachian area, we are completing the construction of our new Snow Shoe gathering system in Centre County, Pennsylvania. This is a fee-based gathering system consisting of approximately seven miles of 16” and 24” pipeline and a related compressor station. The construction of the pipeline has been completed. Since the compressor station will not be required initially to flow gas, we are going to postpone the construction of the compressor station until it is required. We will reevaluate the construction of the compressor station as warranted. We expect this system will be operational and flowing gas before the end of the year. 

Our 2015 estimated capital expenditures for the midstream segment are $59.7 million.

Financial Condition and Liquidity

Summary

Our financial condition and liquidity depends on the cash flow from our operations and borrowings under our credit agreement. The principal factors determining our cash flow are:
 
the quantity of natural gas, oil, and NGLs we produce;
the prices we receive for our natural gas, oil, and NGLs production;
the demand for and the dayrates we receive for our drilling rigs; and
the fees and margins we obtain from our natural gas gathering and processing contracts.

 
 
Nine Months Ended
 
%
Change
 
 
September 30,
 
 
 
2015
 
2014
 
 
 
(In thousands except percentages)
Net cash provided by operating activities
 
$
381,482

 
$
549,527

 
(31
)%
Net cash used in investing activities
 
(474,190
)
 
(636,761
)
 
(26
)%
Net cash provided by financing activities
 
92,553

 
69,536

 
33
 %
Net decrease in cash and cash equivalents
 
$
(155
)
 
$
(17,698
)
 
 

Cash Flows from Operating Activities

Our operating cash flow is primarily influenced by the prices for and the quantity of our oil, NGLs, and natural gas production; settlements of derivative contracts; third-party demand for our drilling rigs and mid-stream services; and the rates we can charge for those services. Our cash flows from operating activities are also affected by changes in working capital.

Net cash provided by operating activities in the first nine months of 2015 decreased by $168.0 million from the first nine months of 2014 due primarily to lower revenues due to lower commodity prices and lower rig utilization partially offset by $25.7 million we recorded in early termination fees and by changes in operating assets and liabilities related to the timing of cash receipts and disbursements.

Cash Flows from Investing Activities

We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration for and production of oil, NGLs, and natural gas. These capital expenditures are necessary to limit inherent declines in production, which is typical in the capital-intensive oil and natural gas industry.

26



Cash flows used in investing activities decreased by $162.6 million for the first nine months of 2015 compared to the first nine months of 2014. The change was due primarily to a decrease in capital expenditures partially offset by a decrease in the proceeds received from the disposition of assets. See additional information on capital expenditures below under Capital Requirements.

Cash Flows from Financing Activities

Cash flows provided by financing activities increased by $23.0 million for the first nine months of 2015 compared to the first nine months of 2014. This increase was primarily due to borrowings under our credit agreement offset partially by a decrease in our book overdrafts (checks issued but not presented to our bank for payment before the end of the period).

At September 30, 2015, we had unrestricted cash totaling $0.9 million and had borrowed $261.7 million of the $500.0 million we had elected to then have available under our credit agreement. Our credit agreement is used primarily for working capital and capital expenditures.

The following is a summary of certain financial information as of September 30, 2015 and 2014 and for the nine months ended September 30, 2015 and 2014:
 
 
September 30,
 
%
Change (1)
 
 
2015
 
2014
 
 
 
(In thousands except percentages)
Working capital
 
$
(31,681
)
 
$
(131,212
)
 
76
 %
Long-term debt
 
$
908,234

 
$
676,843

 
34
 %
Shareholders’ equity
 
$
1,617,957

 
$
2,367,500

 
(32
)%
Net income (loss)
 
$
(728,024
)
 
$
178,827

 
NM

_______________________
(1)
NM - A percentage calculation is not meaningful due to a percentage greater than 200.


27


The following table summarizes certain operating information:
 
 
Nine Months Ended
 
 
 
 
September 30,
 
%
Change
 
 
2015
 
2014
 
Oil and Natural Gas:
 
 
 
 
 
 
Oil production (MBbls)
 
2,996

 
2,801

 
7
 %
NGLs production (MBbls)
 
3,954

 
3,376

 
17
 %
Natural gas production (MMcf)
 
49,650

 
43,424

 
14
 %
Average oil price per barrel received
 
$
51.46

 
$
92.44

 
(44
)%
Average oil price per barrel received excluding derivatives
 
$
46.80

 
$
96.34

 
(51
)%
Average NGLs price per barrel received
 
$
9.83

 
$
33.05

 
(70
)%
Average NGLs price per barrel received excluding derivatives
 
$
9.83

 
$
33.05

 
(70
)%
Average natural gas price per Mcf received
 
$
2.76

 
$
3.99

 
(31
)%
Average natural gas price per Mcf received excluding derivatives
 
$
2.39

 
$
4.17

 
(43
)%
Contract Drilling:
 
 
 
 
 
 
Average number of our drilling rigs in use during the period
 
37.3

 
73.5

 
(49
)%
Total number of drilling rigs available for use at the end of the period
 
94

 
119

 
(21
)%
Average dayrate
 
$
19,669

 
$
19,876

 
(1
)%
Mid-Stream:
 
 
 
 
 
 
Gas gathered—Mcf/day
 
351,619

 
316,658

 
11
 %
Gas processed—Mcf/day
 
186,929

 
160,373

 
17
 %
Gas liquids sold—gallons/day
 
582,760

 
748,805

 
(22
)%
Number of natural gas gathering systems (1)
 
25

 
38

 
(34
)%
Number of processing plants
 
13

 
14

 
(7
)%
_______________________ 
(1)
In 2015, our mid-stream segment transferred 11 natural gas gathering systems to our oil and natural gas segment.

Working Capital

Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative activity. We had negative working capital of $31.7 million and $131.2 million as of September 30, 2015 and 2014, respectively. This is primarily from the timing of our accounts payable associated with our capital expenditures. Our credit agreement is used primarily for working capital and capital expenditures. At September 30, 2015, we had borrowed $261.7 million of the $500.0 million currently available to us under our credit agreement. The effect of our derivative contracts increased working capital by $11.5 million as of September 30, 2015 and increased working capital by $4.0 million as of September 30, 2014.

Oil and Natural Gas Operations

Any significant change in oil, NGLs, or natural gas prices has a material effect on our revenues, cash flow, and the value of our oil, NGLs, and natural gas reserves. Prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances, and by worldwide oil price levels. Domestic oil prices are primarily influenced by global oil market developments. All of these factors are beyond our control and we cannot predict nor measure their future impact on the prices we will receive.

Based on our first nine months of 2015 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of derivatives, would cause a corresponding $526,000 per month ($6.3 million annualized) change in our pre-tax operating cash flow. The average price we received for our natural gas production, including the effect of derivatives, during the first nine months of 2015 was $2.76 compared to $3.99 for the first nine months of 2014. Based on our first nine months of 2015 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $321,000 per month ($3.8 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of derivatives, would have a $420,000 per month ($5.0 million annualized) change in our pre-tax operating cash flow. In the first nine months of 2015, our average oil price per barrel received, including the effect of

28


derivatives, was $51.46 compared with an average oil price, including the effect of derivatives, of $92.44 in the first nine months of 2014 and our first nine months of 2015 average NGLs price per barrel received was $9.83 compared with an average NGLs price per barrel of $33.05 in the first nine months of 2014.

Because commodity prices affect the value of our oil, NGLs, and natural gas reserves, declines in those prices can cause a decline in the carrying value of our oil and natural gas properties. In the first three quarters of 2015, the unamortized cost of our oil and gas properties exceeded the ceiling of our proved oil, NGLs, and natural gas reserves. As a result, we recorded in March of 2015 a non-cash ceiling test write down of $400.6 million pre-tax ($249.4 million, net of tax) and in June of 2015, we recorded a non-cash ceiling test write-down of $410.5 million pre-tax ($255.6 million, net of tax). Then in September of 2015, we recorded a a non-cash ceiling test write-down of $329.9 million pre-tax ($205.4 million, net of tax). At September 30, 2015, the 12-month average unescalated prices were $59.21 per barrel of oil, $23.91 per barrel of NGLs, and $3.06 per Mcf of natural gas, then adjusted for price differentials.

We expect to incur a non-cash ceiling test write-down in the fourth quarter of 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward reserve revisions, reserve additions, and tax attributes. Subject to these numerous factors and inherent limitations, holding these factors constant and only adjusting the 12-month average price to an estimated fourth quarter ending average (holding October 2015 prices constant for the remaining two months of 2015), we currently anticipate that we could recognize an impairment in the fourth quarter of 2015 of approximately $260 million pre-tax. The estimated fourth quarter 2015 impairment is partially the result of a decrease in our proved undeveloped reserves of approximately 49%. This decrease was primarily due to certain locations no longer being economical under the adjusted 12-month average price for the fourth quarter. Based on this estimated 12-month average price, we would eliminate those locations from our future development plans. After the end of the year, the impact of the significantly higher commodity prices from 2014 used in the ceiling test 12-month average price calculation will lessen as those prices will no longer be used in the ceiling test. Given the uncertainty associated with the factors used in calculating our estimate of both our future period ceiling test write-down and the decrease in our undeveloped reserves, these estimates should not necessarily be construed as indicative of our future development plans or financial results.

Price declines can also adversely affect future semi-annual determinations of the amount we can borrow under our credit agreement since that determination is based mainly on the value of our oil, NGLs, and natural gas reserves. Such a reduction could limit our ability to carry out our planned capital projects. Effective with the October 2015 redetermination, the lenders under our credit agreement decreased our borrowing base from $725.0 million to $550.0 million. This new amount is above the $500.0 million commitment we have elected under the credit agreement.

Our natural gas production is sold to intrastate and interstate pipelines and to independent marketing firms and gatherers under contracts with terms ranging from one month to five years. Our oil production is sold to independent marketing firms generally in six month increments.

Contract Drilling Operations

Many factors influence the number of drilling rigs we are working at any given time and the costs and revenues associated with that work. These factors include the demand for drilling rigs in our areas of operation, competition from other drilling contractors, the prevailing prices for oil, NGLs, and natural gas, availability and cost of labor to run our drilling rigs, and our ability to supply the equipment needed.

Although our rig personnel are a key component to the overall success of our drilling services, with the present conditions existing in the drilling industry we do not anticipate increases in the compensation paid to those personnel in the near term.

Low commodity prices continue to curtail our customer drilling budgets and demand for our drilling rigs. As a result, we are experiencing reduced drilling rig utilization. Almost all of our working drilling rigs in 2015 have been drilling horizontal or directional wells. Our drilling rig fleet consists of drilling rigs capable of meeting our customers' demands whether it be for oil, natural gas, or NGLs and whether it be for shallow, deep, vertical, or horizontal type drilling. Current and future demand for drilling rigs and the availability of drilling rigs to meet that demand will affect our future dayrates. For the first nine months of 2015, our average dayrate was $19,669 per day compared to $19,876 per day for the first nine months of 2014. The average number of our drilling rigs used in the first nine months of 2015 was 37.3 drilling rigs compared with 73.5 drilling rigs in the first nine months of 2014. Based on the average utilization of our drilling rigs during the first nine months of 2015, a $100 per day change in dayrates has a $3,730 per day ($1.4 million annualized) change in our pre-tax operating cash flow.


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Our contract drilling segment also provides drilling services for our oil and natural gas segment. Some of the drilling services we perform on our properties are, depending on the timing of those services, deemed to be associated with acquiring an ownership interest in the property. In those cases, revenues and expenses for those drilling services are eliminated in our statement of operations, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $19.1 million and $66.4 million for the first nine months of 2015 and 2014, respectively, from our contract drilling segment and eliminated the associated operating expense of $15.4 million and $46.4 million during the first nine months of 2015 and 2014, respectively, yielding $3.7 million and $20.0 million during the first nine months of 2015 and 2014, respectively, as a reduction to the carrying value of our oil and natural gas properties.

In December 2014, we removed from service 31 drilling rigs, some older top drives, and certain drill pipe no longer marketable under the current environment and based on estimated market value from third party assessments (Level 3 fair value measurement), we recorded a write-down of approximately $74.3 million pre-tax. During the first quarter of 2015, we sold one of these drilling rigs to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $0.3 million net book value of the drilling rig resulting in a gain of $7,900. During the second quarter, we recorded an additional write-down on the remaining drilling rigs and other equipment of approximately $8.3 million pre-tax based on the estimated market value from similar auctions. During the third quarter we sold the remaining 30 drilling rigs and most of the equipment in an auction. The proceeds from the sale of those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax. The equipment that was not sold at the auction will be sold within the next twelve months and remain classified as assets held for sale. The net book value of those assets is $5.3 million.

Our goodwill is all related to our contract drilling segment and goodwill is not amortized, but an impairment test is performed at least annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. The decline in commodity prices has worsened through 2015 resulting in reductions in the number of our drilling rigs working and the rates we charge for them and given this triggering event, we performed impairment testing on our goodwill. Based on the results of our assessment, no goodwill impairment was recorded as of September 30, 2015. A period of sustained reduced commodity prices could result in a non-cash goodwill impairment in future periods.

Mid-Stream Operations

Our mid-stream segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates three natural gas treatment plants, 13 processing plants, 25 gathering systems, and approximately 1,450 miles of pipeline. It operates in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. Besides serving third parties, this segment also enhances our ability to gather and market our own natural gas and NGLs and serving as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first nine months of 2015 and 2014, our mid-stream operations purchased $47.2 million and $65.7 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $5.7 million and $6.8 million, respectively. Intercompany revenue from services and purchases of production between this business segment and our oil and natural gas segment has been eliminated in our unaudited condensed consolidated financial statements.

This segment gathered an average of 351,619 Mcf per day in the first nine months of 2015 compared to 316,658 Mcf per day in the first nine months of 2014. It processed an average of 186,929 Mcf per day in the first nine months of 2015 compared to 160,373 Mcf per day in the first nine months of 2014. The amount of NGLs sold was 582,760 gallons per day in the first nine months of 2015 compared to 748,805 gallons per day in the first nine months of 2014. Gas gathering volumes per day in the first nine months of 2015 increased 11% compared to the first nine months of 2014 primarily from an increase in the number of wells connected to our systems between the comparative periods. Processed volumes for the first nine months of 2015 increased 17% over the first nine months of 2014 due primarily to new wells connected. NGLs sold decreased 22% from the comparative period due to being in ethane rejection mode.

Our Credit Agreement and Senior Subordinated Notes

Credit Agreement. On April 10, 2015, we amended our Senior Credit Agreement (credit agreement) to extend the maturity date from September 13, 2016 to April 10, 2020. The amount we can borrow is the lesser of the amount we elect (from time to time) as the commitment amount or the value of the borrowing base as determined by the lenders (currently $550.0 million), but in either event not to exceed the maximum credit agreement amount of $900.0 million. Our current elected commitment amount is $500.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% 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. To date, for this new amendment, we paid $2.6 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement.

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The current lenders under our credit agreement and their respective participation interests are:
Lender
 
Participation
Interest
BOK (BOKF, NA, dba Bank of Oklahoma)
 
17
%
Compass Bank
 
17
%
BMO Harris Financing, Inc.
 
15
%
Bank of America, N.A.
 
15
%
Wells Fargo Bank, N.A.
 
8
%
Comerica Bank
 
8
%
CIBC
 
8
%
Toronto Dominion (New York), LLC
 
8
%
The Bank of Nova Scotia
 
4
%
 
 
100
%

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. Effective with the October 2015 redetermination, the lenders under our credit agreement decreased our borrowing base from $725.0 million to $550.0 million. 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 1.75% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the 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, 2015 and October 23, 2015, borrowings were $261.7 million and $273.0 million, respectively.

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 (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; and
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, 2015, 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). 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 connection with the issuance of the Notes we incurred $14.7 million of fees that are being amortized as debt issuance cost over the life of the Notes.

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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 and providing for issuing the Notes. The Guarantors are all 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 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.

Before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. 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 September 30, 2015.

Capital Requirements

Oil and Natural Gas Segment Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward future growth. Our decisions to increase our oil, NGLs, and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential, and opportunities to obtain financing under the circumstances involved, all of which provide us with flexibility in deciding when and if to incur these costs. We completed drilling 42 gross wells (28.29 net wells) in the first nine months of 2015 compared to 130 gross wells (85.45 net wells) in the first nine months of 2014. Total capital expenditures for oil and gas properties on the full cost method for the first nine months of 2015, excluding an $8.6 million reduction in the ARO liability, totaled $220.0 million. Total capital expenditures for the first nine months of 2014, excluding a $40.5 million reduction in the ARO liability, totaled $572.9 million.

Currently we plan to participate in drilling approximately 50-60 gross wells in 2015 and our total estimated capital expenditures (excluding any possible acquisitions) for this segment are approximately $278.5 million. Whether we can drill the full number of wells planned depends on several factors, many of which are beyond our control, including the availability of drilling rigs, availability of pressure pumping services, prices for oil, NGLs, and natural gas, demand for oil, NGLs, and natural gas, the cost to drill wells, the weather, and the efforts of outside industry partners.

Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. In December 2014, we removed from service 31 drilling rigs, some older top drives, and certain drill pipe no longer marketable under the current environment and based on estimated market value from third party assessments (Level 3 fair value measurement), we recorded a write-down of approximately $74.3 million pre-tax. During the first quarter of 2015, we sold one of these drilling rigs to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $0.3 million net book value of the drilling rig resulting in a gain of $7,900. During the second quarter, we recorded an additional write-down on the remaining drilling rigs and other equipment of approximately $8.3 million pre-tax based on the estimated market value from similar auctions. During the third quarter we sold the remaining 30 drilling rigs and most of the equipment in an auction. The proceeds from the sale of those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax. The remaining equipment that was not sold at the auction will be sold within the next twelve months and remain classified as assets held for sale. The net book value of those assets is $5.3 million.

We have completed our current new BOSS drilling rig program for 2015. Eight new BOSS drilling rigs have been placed into service. Some of the long lead time components for three additional BOSS drilling rigs were ordered during 2014 and will be delivered in the next twelve months. Currently, we do not have any contracts to build new BOSS drilling rigs.

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Our estimated 2015 capital expenditures for this segment are $86.1 million. At September 30, 2015, we had commitments to purchase approximately $6.5 million for drilling equipment within the next year. We have spent $81.6 million for capital expenditures, including $57.8 million for the BOSS drilling rigs during the first nine months of 2015, compared to $121.3 million for capital expenditures, including $66.0 million for the BOSS drilling rigs, during the first nine months of 2014.

Mid-Stream Acquisitions and Capital Expenditures. With the completion of the connection of the Buffalo Wallow gathering system t