10-Q 1 unt-2013930x10q.htm 10-Q UNT-2013.9.30-10Q
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, 2013
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 25, 2013, 49,106,378 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 quarterly report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. All statements, other than statements of historical facts, included in this quarterly report, which address activities, events, or developments which 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.
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 number of wells we plan to drill or rework;
prices for oil, 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, NGLs, or natural gas production to established pipeline systems;
impact of federal and state legislative and regulatory actions impacting our costs and increasing operating restrictions or delays as well as other adverse impacts on our business;
our projected production guidelines for the year;
our anticipated capital budgets; and
the number of wells our oil and natural gas segment plans to drill during the year.
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 as well as other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to a number of 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 that we pursue;
demand for our land drilling services;
changes in laws or regulations;
decreases or increases in commodity prices; 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 the occurrence of unanticipated events.

2


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
September 30, 2013
 
December 31, 2012
 
(In thousands except share amounts)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
1,741

 
$
974

Accounts receivable, net of allowance for doubtful accounts of $5,342 and $5,343 at September 30, 2013 and at December 31, 2012, respectively
141,817

 
146,046

Materials and supplies
10,330

 
8,563

Current derivative asset (Note 10)
4,514

 
16,552

Current income tax receivable
1,389

 
901

Current deferred tax asset
9,371

 
8,765

Prepaid expenses and other
12,413

 
13,843

Total current assets
181,575

 
195,644

Property and equipment:
 
 
 
Oil and natural gas properties on the full cost method:
 
 
 
Proved properties
4,061,108

 
3,822,381

Undeveloped leasehold not being amortized
589,227

 
521,659

Drilling equipment
1,484,928

 
1,478,645

Gas gathering and processing equipment
538,258

 
461,629

Transportation equipment
39,286

 
37,728

Other
74,802

 
62,840

 
6,787,609

 
6,384,882

Less accumulated depreciation, depletion, amortization, and impairment
3,133,717

 
2,907,660

Net property and equipment
3,653,892

 
3,477,222

Debt issuance cost
12,241

 
13,432

Goodwill
62,808

 
62,808

Other intangible assets, net

 
680

Non-current derivative asset (Note 10)
1,133

 

Other assets
13,046

 
11,334

Total assets
$
3,924,695

 
$
3,761,120


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, 2013
 
December 31, 2012
 
(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
132,633

 
$
138,811

Accrued liabilities (Note 5)
78,557

 
54,098

Current portion of derivative liabilities (Note 10)
6,480

 
1,948

Current portion of other long-term liabilities (Note 6)
11,985

 
12,282

Total current liabilities
229,655

 
207,139

Long-term debt (Note 6)
645,584

 
716,359

Non-current derivative liabilities (Note 10)
938

 
562

Other long-term liabilities (Note 6)
158,161

 
166,983

Deferred income taxes
773,412

 
695,776

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, 49,091,928 and 48,581,948 shares issued, respectively
9,655

 
9,594

Capital in excess of par value
441,291

 
423,603

Accumulated other comprehensive income (loss) (Note 12)
(963
)
 
7,587

Retained earnings
1,666,962

 
1,533,517

Total shareholders’ equity
2,116,945

 
1,974,301

Total liabilities and shareholders’ equity
$
3,924,695

 
$
3,761,120


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


4


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2013
 
2012
 
2013
 
2012
 
(In thousands except per share amounts)
Revenues:
 
 
 
 
 
 
 
Oil and natural gas
$
157,320

 
$
135,435

 
$
475,728

 
$
402,366

Contract drilling
100,647

 
133,420

 
313,180

 
421,198

Gas gathering and processing
75,809

 
52,935

 
203,821

 
159,977

Total revenues
333,776

 
321,790

 
992,729

 
983,541

Expenses:
 
 
 
 
 
 
 
Oil and natural gas:
 
 
 
 
 
 
 
Operating costs
50,139

 
36,147

 
138,171

 
105,035

Depreciation, depletion, and amortization
56,294

 
44,489

 
163,612

 
153,839

Impairment of oil and natural gas properties (Note 2)

 

 

 
115,874

Contract drilling:
 
 
 
 
 
 
 
Operating costs
58,988

 
72,988

 
188,580

 
223,980

Depreciation
17,402

 
20,094

 
52,570

 
62,660

Gas gathering and processing:
 
 
 
 
 
 
 
Operating costs
63,098

 
46,267

 
172,065

 
136,243

Depreciation and amortization
8,773

 
5,884

 
24,143

 
16,330

General and administrative
9,936

 
8,434

 
28,288

 
23,814

Gain on disposition of assets
(4,345
)
 
(44
)
 
(7,744
)
 
(1,283
)
Total operating expenses
260,285

 
234,259

 
759,685

 
836,492

Income from operations
73,491

 
87,531

 
233,044

 
147,049

Other income (expense):
 
 
 
 
 
 
 
Interest, net
(3,625
)
 
(7,087
)
 
(11,777
)
 
(11,455
)
Loss on derivatives not designated as hedges and hedge ineffectiveness, net
(13,760
)
 
(4,015
)
 
(3,340
)
 
(4,621
)
Other
(14
)
 
(59
)
 
(171
)
 
(123
)
Total other income (expense)
(17,399
)
 
(11,161
)
 
(15,288
)
 
(16,199
)
Income before income taxes
56,092

 
76,370

 
217,756

 
130,850

Income tax expense:
 
 
 
 
 
 
 
Current
2,111

 
2,516

 
6,745

 
450

Deferred
19,749

 
27,268

 
77,566

 
50,677

Total income taxes
21,860

 
29,784

 
84,311

 
51,127

Net income
$
34,232

 
$
46,586

 
$
133,445

 
$
79,723

Net income per common share:
 
 
 
 
 
 
 
Basic
$
0.71

 
$
0.97

 
$
2.77

 
$
1.66

Diluted
$
0.70

 
$
0.97

 
$
2.75

 
$
1.66


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


5


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Net income
$
34,232

 
$
46,586

 
$
133,445

 
$
79,723

Other comprehensive income (loss), net of taxes:
 
 
 
 
 
 
 
Change in value of derivative instruments used as cash flow hedges, net of tax of ($3,013), ($8,838), ($5,517), and $7,377
(4,797
)
 
(14,137
)
 
(8,617
)
 
11,353

Reclassification - derivative settlements, net of tax of $1,240, ($5,523), $63, and ($14,793)
1,970

 
(8,720
)
 
139

 
(23,296
)
Ineffective portion of derivatives, net of tax of $97, $1,560, ($44), and $1,792
155

 
2,455

 
(72
)
 
2,829

Comprehensive income
$
31,560

 
$
26,184

 
$
124,895

 
$
70,609


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


6


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
Nine Months Ended
September 30,
 
2013
 
2012
 
(In thousands)
OPERATING ACTIVITIES:
 
 
 
Net income
$
133,445

 
$
79,723

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion, and amortization
242,590

 
234,350

Impairment of oil and natural gas properties (Note 2)

 
115,874

Loss on derivatives
1,765

 
4,621

Deferred tax expense
77,566

 
50,677

Gain on disposition of assets
(7,744
)
 
(1,283
)
Stock compensation plans
16,652

 
12,271

Other, net
4,263

 
3,376

Changes in operating assets and liabilities increasing (decreasing) cash:
 
 
 
Accounts receivable
1,888

 
4,516

Accounts payable
320

 
(11,753
)
Material and supplies
(1,767
)
 
(1,949
)
Accrued liabilities
31,041

 
23,195

Other, net
942

 
(1,478
)
Net cash provided by operating activities
500,961

 
512,140

INVESTING ACTIVITIES:
 
 
 
Capital expenditures
(512,574
)
 
(584,858
)
Producing property and other acquisitions (Note 3)

 
(600,321
)
Proceeds from disposition of assets
89,916

 
296,582

Net cash used in investing activities
(422,658
)
 
(888,597
)
FINANCING ACTIVITIES:
 
 
 
Borrowings under credit agreement
222,500

 
543,700

Payments under credit agreement
(293,600
)
 
(593,700
)
Proceeds from issuance of senior subordinated notes, net of debt issuance costs and discount

 
386,274

Proceeds from exercise of stock options
578

 
90

Book overdrafts
(7,014
)
 
40,281

Net cash provided by (used in) financing activities
(77,536
)
 
376,645

Net increase in cash and cash equivalents
767

 
188

Cash and cash equivalents, beginning of period
974

 
835

Cash and cash equivalents, end of period
$
1,741

 
$
1,023

Supplemental disclosure of cash flow information:
 
 
 
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
$
(516
)
 
$
26,477

Non-cash additions (reductions) to oil and natural gas properties related to asset retirement obligations
$
(16,417
)
 
$
45,188


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

7


UNIT CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PREPARATION AND PRESENTATION
The accompanying unaudited condensed consolidated financial statements in this quarterly 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, as appropriate, 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 quarterly report should be read in conjunction with the audited consolidated financial statements and notes included in our Form 10-K, filed February 26, 2013, for the year ended December 31, 2012.
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, 2013 and December 31, 2012;
• Statements of Income for the three and nine months ended September 30, 2013 and 2012;
• Statements of Comprehensive Income for the three and nine months ended September 30, 2013 and 2012; and
• Statements of Cash Flows for the nine months ended September 30, 2013 and 2012.
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, 2013 and 2012 are not necessarily indicative of the results to be realized for the full year in the case of 2013, or that we realized for the full year of 2012.
Certain amounts in the accompanying unaudited condensed consolidated financial statements for prior periods have been reclassified to conform to current year presentation. Certain financial statement captions were expanded or combined with no impact to consolidated net income or shareholders' equity.
With respect to the unaudited financial information for the three and nine month periods ended September 30, 2013 and 2012, our auditors, PricewaterhouseCoopers LLP, reported that it applied limited procedures in accordance with professional standards in reviewing that information. Its separate report, dated November 5, 2013, which is included in this quarterly report, states that it did not audit and it does not express an opinion on that unaudited financial information. Accordingly, the degree of 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 adjusted for any cash flow hedges), 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. In the event the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short period of time. Once incurred, a write-down of oil and natural gas properties is not reversible.
For the quarter ended June 30, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased significantly resulting in a non-cash ceiling test write down of $115.9 million pre-tax ($72.1 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination as of June 30, 2012, consisted of swaps

8


covering 2.9 MMBoe in 2012 and 4.5 MMBoe in 2013. The effect of those hedges on the June 30, 2012 ceiling test was a $32.5 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties.
At September 30, 2013, the 12-month average commodity prices, including the discounted value of our cash flow hedges, were at levels that did not require us to take a write-down of our oil and natural gas properties. If there are declines in the 12-month average prices, including the discounted value of our cash flow hedges, we may be required to record a write-down in future periods.
Our qualifying cash flow hedges used in the ceiling test determination as of September 30, 2013, consisted of swaps and collars covering 1.7 MMBoe in 2013. The effect of those hedges on the September 30, 2013 ceiling test was a $2.1 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Even without the impact of those hedges, we would not have been required to take a write-down for the quarter. Our oil, NGLs, and natural gas hedging is discussed in Note 10 of the Notes to our Unaudited Condensed Consolidated Financial Statements.
 
NOTE 3 – ACQUISITIONS AND DIVESTITURES
On September 17, 2012, we closed on the acquisition of certain oil and natural gas assets from Noble Energy, Inc. (Noble). The acquisition included approximately 83,000 net acres primarily in the Granite Wash, Cleveland, and various other plays in western Oklahoma and the Texas Panhandle. The amount paid after final closing adjustments was $592.6 million.
As of April 1, 2012, the effective date of the Noble acquisition, the estimated proved reserves of the acquired properties were 44 million barrels of oil equivalent (MMBoe). The acquisition added approximately 24,000 net acres to our Granite Wash core area in the Texas Panhandle with significant resource potential including approximately 600 horizontal drilling locations. The total acreage acquired in western Oklahoma was approximately 59,000 net acres and is characterized by high working interest and operatorship, 95% of which is held by production. We also received four gathering systems as part of the transaction and other miscellaneous assets.
The Noble acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the purchase price and the estimated values of assets acquired and liabilities assumed. It was based on information available to us at the time the unaudited condensed consolidated financial statements were prepared. We believe these estimates are reasonable; however, the estimates are subject to change as additional information becomes available and is assessed by us (in thousands):
Adjusted Purchase Price
 
Total consideration given
$
592,627

 
 
Adjusted Allocation of Purchase Price
 
Oil and natural gas properties included in the full cost pool:
 
Proved oil and natural gas properties
$
260,799

Undeveloped oil and natural gas properties
353,343

Total oil and natural gas properties included in the full cost pool (1)
614,142

Equipment and facilities
25,163

Asset retirement obligation
(46,678
)
Fair value of net assets acquired
$
592,627

(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates.
Pro Forma Financial Information
The following unaudited pro forma financial information is presented to reflect the operations of the acquired assets as if the acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from the historical accounting records of the seller adjusted for estimated transaction costs, depreciation, depletion and amortization, ceiling test impact, general and administrative expenses, capitalized interest, and interest on the 400.0 million of bonds issued along with additional borrowings under our credit facility to finance the acquisition. The unaudited pro forma financial

9


information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of our expected future results of operations. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the acquisition or any estimated costs that will be incurred to integrate these assets. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2012
 
(In thousands, except per share data)
Pro forma:
 
 
 
Revenues
$
335,394

 
$
1,041,350

Net income
$
47,186

 
$
140,670

Net income per common share:
 
 
 
Basic
$
0.98

 
$
2.94

Diluted
$
0.98

 
$
2.92

2012 Divestitures
We completed the following divestitures in 2012, all of which were accounted for as adjustments to the full cost pool with no gain or loss recognized:
In September 2012, we sold our interest in certain Bakken properties (located in North Dakota). The proceeds, net of related expenses, were $226.6 million.
In September 2012, we sold certain oil and natural gas assets located in Brazos and Madison counties of Texas, for approximately $44.1 million.
2013 Divestitures
In August 2013, we sold additional Bakken property interests. The proceeds, net of related expenses, were $57.1 million. These proceeds were accounted for as adjustments to the full cost pool with no gain or loss recognized.
Other
The acquisition and divestitures completed in the third quarter 2012, were structured to allow us to secure like-kind exchange tax treatment for the transactions under Section 1031 of the Internal Revenue Code.

NOTE 4 – EARNINGS PER SHARE
Information related to the calculation of earnings per share follows:
 
Income
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
(In thousands except per share amounts)
For the three months ended September 30, 2013
 
 
 
 
 
Basic earnings per common share
$
34,232

 
48,254

 
$
0.71

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

 
404

 
(0.01
)
Diluted earnings per common share
$
34,232

 
48,658

 
$
0.70

For the three months ended September 30, 2012
 
 
 
 
 
Basic earnings per common share
$
46,586

 
47,938

 
$
0.97

Effect of dilutive stock options, restricted stock, and SARs

 
263

 

Diluted earnings per common share
$
46,586

 
48,201

 
$
0.97



10


The following table shows the number of stock options and SARs (and their average exercise price) not included in the prior calculation because their option exercise prices were greater than the average market price of our common stock:
 
Three Months Ended
September 30,
 
2013
 
2012
Stock options and SARs
149,665

 
278,901

Average exercise price
$
58.41

 
$
51.57


 
Income
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
(In thousands except per share amounts)
For the nine months ended September 30, 2013
 
 
 
 
 
Basic earnings per common share
$
133,445

 
48,193

 
$
2.77

Effect of dilutive stock options, restricted stock, and SARs

 
317

 
(0.02
)
Diluted earnings per common share
$
133,445

 
48,510

 
$
2.75

For the nine months ended September 30, 2012
 
 
 
 
 
Basic earnings per common share
$
79,723

 
47,891

 
$
1.66

Effect of dilutive stock options, restricted stock, and SARs

 
215

 

Diluted earnings per common share
$
79,723

 
48,106

 
$
1.66


The following table shows the number of stock options and SARs (and their average exercise price) not included in the prior calculation because their option exercise prices were greater than the average market price of our common stock:

 
Nine Months Ended
September 30,
 
2013
 
2012
Stock options and SARs
149,665

 
250,901

Average exercise price
$
58.41

 
$
52.72


NOTE 5 – ACCRUED LIABILITIES
Accrued liabilities consisted of the following:
 
September 30, 2013
 
December 31, 2012
 
(In thousands)
Employee costs
$
23,944

 
$
24,632

Interest payable
17,747

 
6,568

Lease operating expenses
14,738

 
10,903

Taxes
11,563

 
7,308

Other
10,565

 
4,687

Total accrued liabilities
$
78,557

 
$
54,098

  

11


NOTE 6 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
Long-Term Debt
Our long-term debt consisted of (or arose under) the following:
 
 
September 30, 2013
 
December 31, 2012
 
(In thousands)
Credit agreement with an average interest rate of 2.9% at December 31, 2012
$

 
$
71,100

6.625% senior subordinated notes due 2021, net of unamortized discount of $4.4 million
at September 30, 2013 and $4.7 million at December 31, 2012
645,584

 
645,259

Total long-term debt
$
645,584

 
$
716,359


Credit Agreement. On September 5, 2012, we amended our Senior Credit Agreement (credit agreement). The amount available to be borrowed is the lesser of the amount we elect (from time to time) as the commitment amount (currently $500.0 million) or the value of the borrowing base as determined by the lenders (currently $800.0 million), but in either event not to exceed the maximum credit agreement amount of $900.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. In connection with the amendment, we paid $1.5 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. The credit agreement is currently scheduled to mature on September 13, 2016.
The amount of the borrowing base–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. There was no change to the borrowing base as of the October 1, 2013 redetermination. 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 set forth 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 in any event 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 anytime, without a premium or penalty. At September 30, 2013, there were no outstanding borrowings under our credit agreement.
Funds under the credit agreement can be used to finance general working capital requirements for (a) exploration, development, production, and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (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 in excess of 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, 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, 2013, we were in compliance with the covenants contained in the credit agreement.
6.625% Senior Subordinated Notes. On May 18, 2011, we completed the sale of $250.0 million of our 6.625% Senior Subordinated Notes (the 2011 Notes). The 2011 Notes were issued at par and mature on May 15, 2021. We received net

12


proceeds of approximately $244.0 million after deducting fees of approximately $6.0 million. Those fees are being amortized as debt issuance cost over the life of the 2011 Notes. We used the net proceeds to repay outstanding borrowings under our credit agreement, which was $220.3 million on May 18, 2011. The remaining proceeds were used for general working capital purposes.
On July 24, 2012, we completed the sale of $400.0 million aggregate principal amount of senior subordinated notes (the 2012 Notes) due May 15, 2021. Those notes also bear interest at a rate of 6.625% per year. The 2012 Notes were sold at 98.75% of par plus accrued interest from May 15, 2012. We used the net proceeds from the offering to partially finance our acquisition of certain oil and natural gas properties. We incurred $8.7 million of fees that are being amortized as debt issuance cost over the life of the 2012 Notes. 
On November 13, 2012, we registered with the SEC an offer on Form S-4 to exchange the 2012 Notes for additional notes with materially identical terms to our existing registered 2011 Notes. On January 7, 2013, the exchange of all the 2012 Notes was completed. The notes issued in exchange for the 2012 Notes are now registered and treated as a single series of debt securities with the 2011 Notes, bringing the total of the aggregate principal amount of 6.625% senior subordinated notes to $650.0 million (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.
The Notes are guaranteed by our 100% owned domestic direct and indirect subsidiaries (the Guarantors). Unit, as the parent company, has no independent assets or operations. The guarantees are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with their respective Indentures described below. Any subsidiaries of Unit other than the Guarantors are minor. There are no significant restrictions on the ability of Unit to receive funds from its subsidiaries through dividends, loans, advances, or otherwise.
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). The Indenture was supplemented by the First Supplemental Indenture dated as of May 18, 2011 and further supplemented by the Second Supplemental Indenture dated as of January 7, 2013. As supplemented, the Indenture establishes the terms and provides for the issuance of the Notes . The discussion of the Notes is qualified by and subject to the actual terms of the Indenture.
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. Before May 15, 2014, we may on any one or more occasions redeem up to 35% of the original principal amount of the Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, provided that at least 65% of the original principal amount of the Notes remains outstanding after each redemption. In addition, at any time 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. 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 Indenture contains customary events of default. The Indenture 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, 2013.

13


Other Long-Term Liabilities
As of the dates indicated, other long-term liabilities consisted of the following:
 
September 30, 2013
 
December 31, 2012
 
(In thousands)
Asset retirement obligation (ARO) liability
$
133,894

 
$
146,159

Workers’ compensation
20,207

 
18,517

Separation benefit plans
8,991

 
7,972

Gas balancing liability
3,838

 
3,838

Deferred compensation plan
3,216

 
2,779

 
170,146

 
179,265

Less current portion
11,985

 
12,282

Total other long-term liabilities
$
158,161

 
$
166,983


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, 2013 (and through 2018) are $12.0 million, $40.8 million, $5.2 million, $3.9 million, and $3.8 million, respectively.

NOTE 7 – ASSET RETIREMENT OBLIGATIONS
We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All of our AROs relate to the plugging costs associated with our oil and gas wells.
The following table shows certain information about our AROs:
 
Nine Months Ended
September 30,
 
2013
 
2012
 
(In thousands)
ARO liability, January 1:
$
146,159

 
$
96,446

Accretion of discount
4,152

 
3,215

Liability incurred
3,820

 
52,306

Liability settled
(4,071
)
 
(1,606
)
Revision of estimates (1)
(16,166
)

(4,254
)
ARO liability, September 30:
133,894

 
146,107

Less current portion
2,954

 
2,857

Total long-term ARO
$
130,940

 
$
143,250

 
(1)
Plugging liability estimates were revised in both 2013 and 2012 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows.

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS
Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. In July 2013, ASU 2013-11 was issued because GAAP does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendment provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments in this Update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. Early adoption is permitted.  The amendments should be applied prospectively to all unrecognized tax benefits that exist

14


at the effective date. Retrospective application is permitted. We anticipate there will be no effect on our financial position or results of operations when adopted.
Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes. The FASB has issued ASU 2013-10, the amendments in this update permit the Fed Funds Effective Swap Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to U.S. Treasury and LIBOR. The amendments also remove the restriction on using different benchmark rates for similar hedges. The amendments are effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We currently do not have any interest rate hedges at this time.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued ASU 2013-02 to address the presentation of comprehensive income related to ASU 2011-05. The standard requires that companies present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source (e.g., the release due to cash flow hedges from interest rate contracts) and the income statement line items affected by the reclassification (e.g., interest income or interest expense). The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. We chose to present the information in a single note (Note 11 of the Notes to our Unaudited Condensed Consolidated Financial Statements).
Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. In January 2013, the FASB issued ASU 2013-01 to limit the scope of balance sheet offsetting disclosures contained in previously issued guidance in ASU 2011-11—Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards or subject to a master netting arrangement or similar agreement.
Unlike IFRS, GAAP allows companies the option to present net in their balance sheets derivatives that are subject to a legally enforceable netting arrangement with the same party where rights of set-off are only available in the event of default or bankruptcy. To address these differences between IFRS and GAAP, the FASB and the IASB (the Boards) issued an exposure draft that proposed new criteria for netting that were narrower than the current conditions currently in GAAP. Nevertheless, in response to feedback from their respective stakeholders, the Boards decided to retain their existing offsetting models. Instead, the Boards have issued common disclosure requirements related to offsetting arrangements to allow investors to better compare financial statements prepared in accordance with IFRS or GAAP. The amendments in this ASU require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. Derivatives subject to a master netting agreement are the only transactions in this accounting standard that affect us. We provide the effect of netting on our financial position in Note 11 of the Notes to our Unaudited Condensed Consolidated Financial Statements.

NOTE 9 – STOCK-BASED COMPENSATION
For the three and nine months ended September 30, 2013, we recognized stock compensation expense for restricted stock awards of $4.4 million and $12.0 million, respectively. For the same period we also capitalized stock compensation cost for oil and natural gas properties of $1.0 million and $2.6 million, respectively. For these same periods, the tax benefit related to this stock based compensation was $1.8 million and $4.7 million, respectively. The remaining unrecognized compensation cost related to unvested awards at September 30, 2013 is approximately $20.7 million of which $3.3 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.
For the three and nine months ended September 30, 2012, we recognized stock compensation expense for restricted stock awards of $2.9 million and $8.2 million, respectively. For the same period we also capitalized stock compensation cost for oil and natural gas properties of $0.7 million and $2.0 million, respectively. For these same periods, the tax benefit related to this stock based compensation was $1.2 million and $3.2 million, respectively.
We grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as to non-employee directors under our Unit Corporation Stock and Incentive Compensation Plan Amended and Restated May 2, 2012 (the amended plan). A total of 3,300,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan. The amended plan succeeds our previous Non-employee Directors' 2000 Stock Option Plan (the option plan).

15


We did not grant any SARs or stock options during either of the three or nine month periods ending September 30, 2013 and 2012. The following table shows the fair value of the restricted stock awards granted to employees and non-employee directors:  
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2013
 
2012
 
2013
 
2012
Shares granted:
 
 
 
 
 
 
 
Employees

 
2,509

 
448,549

 
370,445

Non employee directors

 

 
21,128

 
24,606

 

 
2,509

 
469,677

 
395,051

Estimated fair value (in millions):
 
 
 
 
 
 
 
Employees
$

 
$
0.1

 
$
21.0

 
$
15.7

Non employee directors

 

 
0.9

 
1.0

 
$

 
$
0.1

 
$
21.9

 
$
16.7

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

 
95
%
 
94
%
 
94
%
Non employee directors
N/A

 
%
 
100
%
 
100
%
The restricted stock awards granted during the three and nine months ended September 30, 2013 and 2012 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, 30% of the shares granted, or 57,405 shares in 2013 and 46,441 shares in 2012 (the performance shares), will cliff vest in the first half of 2016 and 2015, respectively. The actual number of performance shares that vest in 2015 and 2016 will be based on the company’s achievement of certain performance criteria over a three-year period, and will range from 50% to 150% of the restricted shares granted as performance shares. Based on the performance criteria, the participants could receive more than 100% of the performance based shares. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2013 awards for the first nine months of 2013 was $7.1 million.

NOTE 10 – DERIVATIVES
Commodity Derivatives
We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, 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 hedged is based, in part, on our view of current and future market conditions. As of September 30, 2013, our derivative transactions consisted of the following types of hedges:

Swaps. We receive or pay a fixed price for the hedged 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 (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.
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. In August 2012, we determined–on a prospective basis–that we would no longer elect to use cash flow hedge accounting for our economic hedges. Therefore, the change in fair value on all commodity derivatives entered into after that determination will be reflected in the income statement and not in accumulated other comprehensive income (OCI).

16


At September 30, 2013, we had the following outstanding cash flow hedges:
Term
Commodity
Hedged Volume
Weighted Average Fixed
Price for Swaps
Hedged Market
Oct'13 - Dec'13
Crude oil – swap
5,500 Bbl/day
$99.71
WTI – NYMEX
Oct'13 - Dec'13
Natural gas – swap
60,000 MMBtu/day
$3.56
IF – NYMEX (HH)
Oct'13 - Dec'13
Natural gas – collar
20,000 MMBtu/day
$3.25-3.72
IF – NYMEX (HH)

At September 30, 2013, we had the following outstanding non-designated hedges:
Term
Commodity
Hedged Volume
Weighted Average Fixed
Price for Swaps
Hedged Market
Oct'13 - Dec'13
Crude oil – swap
3,000 Bbl/day
$94.59
WTI – NYMEX
Jan'14 - Dec'14
Crude oil – swap
3,000 Bbl/day
$91.77
WTI – NYMEX
Jan'14 - Jun'14
Crude oil – swap
500 Bbl/day
$100.03
WTI – NYMEX
Jan'14 - Dec'14
Crude oil – collar
4,000 Bbl/day
$90.00-96.08
WTI – NYMEX
Oct'13 - Dec'13
Natural gas – swap
20,000 MMBtu/day
$3.94
IF – NYMEX (HH)
Jan'14 - Dec'14
Natural gas – swap
50,000 MMBtu/day
$4.24
IF – NYMEX (HH)

The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
 
 
 
Derivative Assets
 
 
Fair Value
 
Balance Sheet Location
September 30, 2013
 
December 31, 2012
 
 
(In thousands)
Derivatives designated as hedging instruments
 
 
 
 
Commodity derivatives:
 
 
 
 
Current
Current derivative asset
$
486

 
$
13,674

Long-term
Non-current derivative asset

 

Total derivatives designated as hedging instruments
 
486

 
13,674

Derivatives not designated as hedging instruments
 
 
 
 
Commodity derivatives:
 
 
 
 
Current
Current derivative asset
4,028

 
2,878

Long-term
Non-current derivative asset
1,133

 

Total derivatives not designated as hedging instruments
 
5,161

 
2,878

Total derivative assets
 
$
5,647

 
$
16,552




17



 
 
Derivative Liabilities
 
 
Fair Value
 
Balance Sheet Location
September 30, 2013
 
December 31, 2012
 
 
(In thousands)
Derivatives designated as hedging instruments
 
 
 
 
Commodity derivatives:
 
 
 
 
Current
Current derivative liabilities
$
1,750

 
$
1,005

Long-term
Non-current derivative liabilities

 

Total derivatives designated as hedging instruments
 
1,750

 
1,005

Derivatives not designated as hedging instruments
 
 
 
 
Commodity derivatives:
 
 
 
 
Current
Current derivative liabilities
4,730

 
943

Long-term
Non-current derivative liabilities
938

 
562

Total derivatives not designated as hedging instruments
 
5,668

 
1,505

Total derivative liabilities
 
$
7,418

 
$
2,510

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.
We recognize in accumulated OCI the effective portion of any changes in fair value for derivatives designated as cash flow hedges and reclassify the recognized gains (losses) on the sales to oil and natural gas revenue as the underlying transactions are settled. As of September 30, 2013 and 2012, we had recognized a loss of $1.0 million and a gain of $9.9 million, net of tax, respectively, in accumulated OCI.
Based on market prices at September 30, 2013, we expect to transfer over the next three months (in the related month of settlement) a loss of approximately $1.0 million, net of tax, into revenue. The cash flow derivative instruments existing as of September 30, 2013 are expected to mature by December 2013.

For our economic hedges that we did not apply cash flow accounting to, any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net in our Unaudited Condensed Consolidated Statements of Income. Changes in the fair value of derivatives designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in OCI until the hedged item is recognized into earnings. When the hedged item is recognized into earnings, it is reported in oil and natural gas revenues. Any change in fair value resulting from ineffectiveness is recognized in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net. Before October 2012, we reported all gains (losses) associated with derivatives in oil and natural gas revenues. We reflect gains (losses) on non-designated hedges and ineffectiveness from cash flow hedges along with other revenue items in other income (expense) below income from operations. Prior year amounts have been reclassified to conform to current year presentation.
This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the nine months ended September 30:
Derivatives in Cash Flow Hedging
Relationships
Amount of Gain or (Loss) Recognized in
Accumulated OCI on Derivative (Effective Portion) (1)
 
2013
 
2012
 
(In thousands)
Commodity derivatives
$
(963
)
 
$
9,912

 
(1) Net of taxes.

18


This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the three months ended September 30:
 
Derivative Instrument
Location of Gain or (Loss) Reclassified 
from Accumulated OCI into Income
& Location of Gain or (Loss) Recognized in Income
Amount of Gain or (Loss)
Reclassified from Accumulated
OCI into Income (1)
 
Amount of Gain or (Loss)
Recognized in Income (2)
 
 
2013
 
2012
 
2013
 
2012
 
 
(In thousands)
Commodity derivatives
Oil and natural gas revenue
$
(3,210
)
 
$
14,243

 
$

 
$

Commodity derivatives
Loss on derivatives not designated as hedges and hedge ineffectiveness, net 

 

 
(252
)
 
(4,015
)
Total
 
$
(3,210
)
 
$
14,243

 
$
(252
)
 
$
(4,015
)
 
(1)
Effective portion of gain (loss).
(2)
Ineffective portion of gain (loss).
This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (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 (1)
 
 
2013
 
2012
 
 
(In thousands)
Commodity derivatives
Loss on derivatives not designated as hedges and hedge ineffectiveness, net
$
(13,508
)
 
$

Total
 
$
(13,508
)
 
$

(1)
Amount settled during the period is a loss of ($2.434) and $0, respectively.

This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the nine months ended September 30:
 
Derivative Instrument
Location of Gain or (Loss) Reclassified 
from Accumulated OCI into Income
& Location of Gain or (Loss) Recognized in Income
Amount of Gain or (Loss)
Reclassified from Accumulated
OCI into Income (1)
 
Amount of Gain or (Loss)
Recognized in Income (2)
 
 
2013
 
2012
 
2013
 
2012
 
 
(In thousands)
Commodity derivatives
Oil and natural gas revenue
$
(202
)
 
$
38,088

 
$

 
$

Commodity derivatives
Loss on derivatives not designated as hedges and hedge ineffectiveness, net 

 

 
116

 
(4,621
)
Total
 
$
(202
)
 
$
38,088

 
$
116

 
$
(4,621
)
 
(1)
Effective portion of gain (loss).
(2)
Ineffective portion of gain (loss).
This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (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 (1)
 
 
2013
 
2012
 
 
(In thousands)
Commodity derivatives
Loss on derivatives not designated as hedges and hedge ineffectiveness, net
$
(3,456
)
 
$

Total
 
$
(3,456
)
 
$

(1)
Amount settled during the period is a loss of ($1.575) and $0, respectively.


19


NOTE 11 – FAIR VALUE MEASUREMENTS
Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value. 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 that are either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.
Level 3 - generally unobservable inputs which are developed based on the best information available and may include our own internal data.
The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments. 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, 2013
 
Level 2
 
Level 3
 
Gross Amounts
 
Effect of Netting
 
Net Amounts Presented
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
Assets
$
8,473

 
$

 
$
8,473

 
$
(2,826
)
 
$
5,647

Liabilities
(7,622
)
 
(2,622
)
 
(10,244
)
 
2,826

 
(7,418
)
 
$
851

 
$
(2,622
)
 
$
(1,771
)
 
$

 
$
(1,771
)
 
 
December 31, 2012
 
Level 2
 
Level 3
 
Gross Amounts
 
Effect of Netting
 
Net Amounts Presented
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
Assets
$
18,555

 
$

 
$
18,555

 
$
(2,003
)
 
$
16,552

Liabilities
(3,918
)
 
(595
)
 
(4,513
)
 
2,003

 
(2,510
)
 
$
14,637

 
$
(595
)
 
$
14,042

 
$

 
$
14,042

All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of September 30, 2013.
Certain natural gas fixed price swaps were transferred from Level 3 to Level 2 as of June 30, 2012 because of improvements in our ability to obtain and corroborate observable significant inputs to assess the fair value. Our policy is to recognize transfers either in or out of fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.
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.

20


Level 3 Fair Value Measurements
Commodity Derivatives. The fair values of our natural gas and crude oil 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 Collars
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Beginning of period
$
1,446

 
$
8,130

 
$
(595
)
 
$
33,615

Total gains or losses:
 
 
 
 
 
 
 
Included in earnings (1)
(3,949
)
 
2,241

 
(2,544
)
 
19,114

Included in other comprehensive income (loss)
(119
)
 
(4,194
)
 
(119
)
 
(7,770
)
Settlements

 
(4,574
)
 
636

 
(21,432
)
Transfers out of Level 3 into Level 2

 

 

 
(21,924
)
End of period
$
(2,622
)
 
$
1,603

 
$
(2,622
)
 
$
1,603

Total losses for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period
$
(3,949
)
 
$
(2,333
)
 
$
(1,908
)
 
$
(2,318
)
(1)
Commodity collars are reported in the Unaudited Condensed Consolidated Statements of Income in oil and natural gas revenues (for cash flow hedges) and loss on derivatives not designated as hedges and hedge ineffectiveness, net, respectively.

The following table provides quantitative information about our Level 3 unobservable inputs at September 30, 2013:
Commodity (1)
Fair Value
Valuation Technique
Unobservable Input
Range
 
(In thousands)
 
 
 
Oil collars
$
(2,503
)
Discounted cash flow
Forward commodity price curve
($7.79) - $6.86
Natural gas collar
$
(119
)
Discounted cash flow
Forward commodity price curve
($0.19) - $0.03
 
(1)
The commodity contracts detailed in this category include non-exchange-traded natural gas and crude oil collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.
Based on our valuation at September 30, 2013, 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 in accordance with accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop these estimates. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
At September 30, 2013, 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 at September 30, 2013 approximates its fair value. 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, 2013 and December 31, 2012 were $645.6 million and

21


$645.3 million, respectively. We estimated the fair value of these Notes using quoted market prices at September 30, 2013 and December 31, 2012 which were $666.3 million and $687.7 million, respectively. These Notes would be classified as Level 2.

NOTE 12 – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Changes in accumulated other comprehensive income (loss) by component, net of tax, for the three months ended September 30 are as follows:
 
Net Gains (Losses) on Cash Flow Hedges
 
2013
 
2012
 
(In thousands)
Balance at July 1:
$
1,709

 
$
30,314

Other comprehensive income (loss) before reclassification
(4,797
)
 
(14,137
)
Amounts reclassified from accumulated other comprehensive income (loss)
2,125

 
(6,265
)
New current-period other comprehensive income (loss)
(2,672
)
 
(20,402
)
Balance at September 30:
$
(963
)
 
$
9,912

Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the three months ended September 30 are as follows:
 
2013
 
2012
 
Affected Line Item in the Statement Where Net Income is Presented
 
(In thousands)
 
 
Net gains (loss) on cash flow hedges
 
 
 
 
 
Commodity derivatives
$
(3,210
)
 
$
14,243

 
Oil and natural gas revenues
Commodity derivatives
(252
)
 
(4,015
)
 
Loss on derivatives not designated as hedges and hedge ineffectiveness, net
 
(3,462
)
 
10,228

 
Total before tax
 
1,337

 
(3,963
)
 
Tax expense (benefit)
Total reclassification for the period
$
(2,125
)
 
$
6,265

 
Net of tax
Changes in accumulated other comprehensive income (loss) by component, net of tax, for the nine months ended September 30 are as follows:
 
Net Gains (Losses) on Cash Flow Hedges
 
2013
 
2012
 
(In thousands)
Balance at January 1:
$
7,587

 
$
19,026

Other comprehensive income (loss) before reclassification
(8,617
)
 
11,353

Amounts reclassified from accumulated other comprehensive income (loss)
67

 
(20,467
)
New current-period other comprehensive income (loss)
(8,550
)
 
(9,114
)
Balance at September 30:
$
(963
)
 
$
9,912


22


Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the nine months ended September 30 are as follows:
 
2013
 
2012
 
Affected Line Item in the Statement Where Net Income is Presented
 
(In thousands)
 
 
Net gains (loss) on cash flow hedges
 
 
 
 
 
Commodity derivatives
$
(202
)
 
$
38,088

 
Oil and natural gas revenues
Commodity derivatives
116

 
(4,621
)
 
Loss on derivatives not designated as hedges and hedge ineffectiveness, net
 
(86
)
 
33,467

 
Total before tax
 
19

 
(13,000
)
 
Tax expense (benefit)
Total reclassification for the period
$
(67
)
 
$
20,467

 
Net of tax


23


NOTE 13 – INDUSTRY SEGMENT INFORMATION
We have three main business segments offering different products and services. They are:
 
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 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 production in Canada is not significant.
The following table provides certain information about each segment's operations:
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2013
 
2012
 
2013
 
2012
 
 
(In thousands)
 
Revenues:
 
 
 
 
 
 
 
 
Oil and natural gas
$
157,320

 
$
135,435

 
$
475,728

 
$
402,366

 
 
 
 
 
 
 
 
 
 
Contract drilling
119,105

 
145,561

 
357,118

 
458,945

 
Elimination of inter-segment revenue
(18,458
)
 
(12,141
)
 
(43,938
)
 
(37,747
)
 
Contract drilling net of inter-segment revenue
100,647

 
133,420

 
313,180

 
421,198

 
 
 
 
 
 
 
 
 
 
Gas gathering and processing
99,007

 
70,394

 
272,073

 
210,550

 
Elimination of inter-segment revenue
(23,198
)
 
(17,459
)
 
(68,252
)
 
(50,573
)
 
Gas gathering and processing net of inter-segment revenue
75,809

 
52,935

 
203,821

 
159,977

 
 
 
 
 
 
 
 
 
 
Total revenues
$
333,776

 
$
321,790

 
$
992,729

 
$
983,541

 
Operating income:
 
 
 
 
 
 
 
 
Oil and natural gas
$
50,887

 
$
54,799

 
$
173,945

 
$
27,618

(2 
) 
Contract drilling
24,257

 
40,338

 
72,030

 
134,558

 
Gas gathering and processing
3,938

 
784

 
7,613

 
7,404

 
Total operating income (1)
79,082

 
95,921

 
253,588

 
169,580

 
General and administrative
(9,936
)
 
(8,434
)
 
(28,288
)
 
(23,814
)
 
Gain on disposition of assets
4,345

 
44

 
7,744

 
1,283

 
Loss on derivatives not designated as hedges and hedge ineffectiveness, net
(13,760
)
 
(4,015
)
 
(3,340
)
 
(4,621
)
 
Interest expense, net
(3,625
)
 
(7,087
)
 
(11,777
)
 
(11,455
)
 
Other
(14
)
 
(59
)
 
(171
)
 
(123
)
 
Income before income taxes
$
56,092

 
$
76,370

 
$
217,756

 
$
130,850

 

(1)
Total operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include non-operating revenues, general corporate expenses, gain on disposition of assets, interest expense, or income taxes.
(2)
In June 2012, we had a non-cash ceiling test write-down of $115.9 million pre-tax ($72.1 million, net of tax).


24


NOTE 14 – SUBSEQUENT EVENT
In October 2013, five of our idle drilling rigs met the criteria for classification as assets held for sale. One drilling rig was sold in October and the other four drilling rigs are under contract to be sold with closings anticipated to occur during the fourth quarter of 2013 and the first quarter of 2014. The drilling rigs are being sold to two separate unaffiliated third-parties. The proceeds for the sale of these assets, less costs to sell, is expected to exceed the approximate $17.2 million net book value of the drilling rigs, both in the aggregate and for each drilling rig.


25


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 Sheets of Unit Corporation and its subsidiaries as of September 30, 2013, and the related Unaudited Condensed Consolidated Statements of Income and Comprehensive Income for the three and nine-month periods ended September 30, 2013 and 2012 and the Unaudited Condensed Consolidated Statements of Cash Flows for the nine-month periods ended September 30, 2013 and 2012. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with 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 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, 2012, and the related consolidated statements of income, shareholders’ equity, and of cash flows for the year then ended (not presented herein), and in our report dated February 26, 2013, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2012, 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 5, 2013


26


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 during the periods discussed. 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 as well as our unaudited condensed consolidated financial statements and related notes with the information contained 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 quarterly report, the success of our consolidated business, as well as that of each of our three operating segments depends, to a large extent, on: the prices we receive for our natural gas, NGLs, and oil production; the demand for oil, NGLs, and natural gas; and, the demand for our drilling rigs which, in turn, influences the amounts we can charge for the use of those drilling rigs. Although all of our current operations (with the exception of a minor amount of production in Canada) are located within the United States, events outside the United States can and do have an impact on us and our industry.
In addition to their direct impact on us, low commodity prices–if sustained for a long period of time–could impact the liquidity of some of our industry partners and customers which, in turn, could limit their ability to meet their financial obligations to us.
Executive Summary
Oil and Natural Gas Segment
Third quarter 2013 production was 4,217,000 barrels of oil equivalent (Boe), a 3% increase over the second quarter of 2013 and a 21% increase over the third quarter of 2012. These increases came primarily from new wells completed in oil and NGLs rich prospects that were brought online and from production associated with 2012 acquisitions.
Third quarter 2013 revenues decreased 5% from the second quarter of 2013 and increased 16% over the third quarter of 2012. The decrease from the second quarter of 2013 was due primarily to decreases in oil production coupled with decreases in natural gas and NGLs prices somewhat offset by increases in natural gas and NGLs production coupled with higher oil prices. The increase over the third quarter of 2012 was due primarily to increased natural gas and NGLs production along with higher oil and NGLs prices.
Our oil prices for the third quarter of 2013 increased 1% over the second quarter of 2013 and increased 5% over the third quarter of 2012. Our NGLs prices decreased 7% from the second quarter of 2013 and increased 32% over the third quarter of 2012. Our natural gas prices decreased 15% and 9% from the second quarter of 2013 and third quarter of 2012, respectively.

27


Direct profit (oil and natural gas revenues less oil and natural gas operating expense) decreased 11% from the second quarter of 2013 and increased 8% over the third quarter of 2012. The decrease from the second quarter of 2013 is due to lower oil production, lower natural gas and NGLs prices, and higher operating costs due primarily to salt water disposal and well servicing costs. The increase over the third quarter of 2012 is due primarily to increases in natural gas and NGLs production and increases in oil and NGLs prices.
Operating cost per Boe produced for the third quarter of 2013 increased 9% over the second quarter of 2013 and increased 15% over the third quarter of 2012. Costs were higher between the third and second quarter of 2013 primarily due to higher salt water disposal costs. Costs were higher between the third quarter of 2013 and the third quarter of 2012 due to costs from additional wells acquired under acquisitions and wells completed during 2013.
For 2013, approximately 8,330 barrels per day of this segment's oil production and approximately 100,000 Mmbtu per day of its natural gas production is currently hedged. The oil production is hedged under swap contracts at an average price of $97.94 per barrel. The natural gas production is hedged by swaps for 80,000 Mmbtu per day and a collar for 20,000 Mmbtu per day. The swap transactions were executed at a comparable average NYMEX price of $3.65. The collar transaction was executed at a comparable average NYMEX floor price of $3.25 and ceiling price of $3.72.
For 2014, 7,248 barrels per day of oil production and 50,000 Mmbtu per day of natural gas production is currently hedged.  The oil production is hedged by swaps for 3,248 barrels per day and collars for 4,000 barrels per day.  The swap transactions were executed at an average price of $92.35 per barrel.  The collar transactions were executed at an average floor price of $90.00 per barrel and ceiling price of $96.08 per barrel.  The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $4.24.
On September 17, 2012, we closed on the acquisition of certain oil and natural gas assets from Noble. The acquisition included approximately 83,000 net acres primarily in the Granite Wash, Cleveland, and various other plays in western Oklahoma and the Texas Panhandle. The final closing adjusted amount paid was $592.6 million.
Also in September 2012, we sold our interests in certain Bakken properties. The proceeds, net of related expenses, were $226.6 million. In addition, we sold certain oil and natural gas assets located in Brazos and Madison Counties, Texas for approximately $44.1 million. In August 2013, we sold additional Bakken property interests. The proceeds, net of related expenses, were $57.1 million. All three dispositions were accounted for as adjustments to the full cost pool with no gain or loss recognized.
As of September 30, 2013, we had completed drilling 102 wells (56.79 net wells). For all of 2013, we plan to participate in the drilling of approximately 170 wells. Our oil and natural gas segment’s estimated capital expenditures are $580.0 million, excluding acquisitions and ARO liability. Our 2013 production guidance is approximately 16.4 to 16.9 MMBoe, an increase of 15% to 19% over 2012, although actual results will continue to be subject to many factors.
Contract Drilling Segment
The rate at which our drilling rigs were used (“our utilization rate”) remained unchanged at 51% for the third quarter of 2013 compared to the second quarter of 2013 and decreased from 58% compared to the third quarter of 2012.
Dayrates for the third quarter of 2013 averaged $19,773, an increase of 1% over the second quarter of 2013 and a 1% decrease from the third quarter of 2012. The decrease was due primarily to the termination of certain contracts during 2012 that had higher rates (drilling rigs that were under long-term contracts, but were terminated early by the operator).
Direct profit (contract drilling revenue less contract drilling operating expense) for the third quarter of 2013 increased 1% over the second quarter of 2013 and decreased 31% from the third quarter of 2012. The decrease from the third quarter of 2012 was due primarily to 13% fewer drilling rigs operating and 14% lower per day revenue. The third quarter of 2012 included $6.7 million in revenue for early termination fees on three drilling rigs that were under long-term contracts but were terminated early by the operator compared to $0.9 million for the termination of one long-term drilling contract in 2013.
Operating cost per day for the third quarter of 2013 decreased 6% from the second quarter of 2013 and decreased 8% from the third quarter of 2012. The decrease from the second quarter of 2013 was primarily due to decreases in indirect costs and worker's compensation expense. The decrease from the third quarter of 2012 was due to lower indirect costs.
With the weakening of natural gas prices over the last several years the demand for drilling rigs in our contract drilling segment shifted to drilling wells focused on oil and NGL production.  Today, almost all of our working drilling rigs are drilling horizontal or directional wells for oil and NGLs. Part of this shift included operators moving to shallower oil plays like the Mississippian play in northern Oklahoma and southern Kansas. These shallower plays tend to use drilling rigs with lower horsepower which have lower dayrates and margins.  As methods for drilling horizontal wells have improved, demand to drill

28


deeper and longer horizontal wells are starting to once again strengthen demand for higher horsepower rigs. All of these factors ultimately affect the demand and mix of the type of drilling rigs used by our customers.
As of September 30, 2013, we had 23 term drilling contracts with original terms ranging from six months to three years. Six of these contracts are up for renewal in the fourth quarter of 2013. Term contracts may contain a fixed rate for the length of the contract or provide for periodic rate adjustments during the term.
During the first quarter of 2012, we sold an idle 600 horsepower mechanical drilling rig to an unaffiliated third-party. We also placed a new 1,500 horsepower, diesel-electric drilling rig into service working under a three year contract in Wyoming. Additionally, during the second quarter of 2012, we placed another new 1,500 horsepower, diesel-electric drilling rig in North Dakota (also under a three year contract).  During the third quarter of 2012, one of our drilling rigs was damaged by a fire. The net book value of the damaged rig equipment was $3.2 million. We expect that all of the net book value of the damaged equipment will be recoverable from insurance proceeds. No personnel were injured in this incident.
In the second quarter of 2013, we sold a 2,000 horsepower electric drilling rig and during the third quarter of 2013, we sold two additional 2,000 horsepower electric drilling rigs. Subsequent to September 30, 2013, we sold another 2,000 horsepower electric drilling rig. All of these sales were to unaffiliated third-parties. Four additional idle 3,000 horsepower drilling rigs are under contract to be sold with closings anticipated to occur during the fourth quarter of 2013 and the first quarter of 2014. The proceeds from these sales will be used in our new drilling rig program, a program we launched to design and build a new proprietary drilling rig, the BOSS rig. We anticipate this drilling rig will position us to more effectively meet the demands of our existing customer as well as allowing us to compete for the work of new customers.
Our estimated 2013 capital expenditures for this segment are $59.0 million. Our plans for the year include continuing to refurbish and upgrade several of our existing drilling rigs in order that those drilling rigs can be used in horizontal drilling operations. Currently, we are in the process of constructing our first BOSS rig, a new prototype 1,500 horsepower AC electric drilling rig. This new drilling rig is expected to be operational in the fourth quarter of 2013, and will operate initially for our oil and natural gas segment. Our second BOSS drilling rig is committed to an operator in North Dakota and is planned to go into service in the second quarter of 2014. We are optimistic that the BOSS drilling rig will continue to be well received by operators and will result in additional new-build contract opportunities.
Mid-Stream Segment
Third quarter 2013 liquids sold per day increased 15% over the second quarter of 2013 and increased 2% over the third quarter of 2012. For the third quarter of 2013, gas processed per day increased 5% over the second quarter of 2013 and increased 8% over the third quarter of 2012. These increases are primarily due to connecting new wells to both existing and newly constructed systems. For the third quarter of 2013, gas gathered per day was essentially unchanged from the second quarter of 2013 and increased 35% over the third quarter of 2012. The increase over the third quarter of 2012 was primarily from new well connects.
NGLs prices in the third quarter of 2013 increased 10% over the prices received in the second quarter of 2013 and increased 30% over the prices received in the third quarter of 2012. Because certain of the 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.
Direct profit (mid-stream revenues less mid-stream operating expense) for the third quarter of 2013 increased 15% over the second quarter of 2013 and increased 91% over the third quarter of 2012. The increase over the second quarter of 2013 is due to higher liquids sold volumes and higher liquids sold prices somewhat offset by lower gas sold revenues and higher cost of gas purchased. The increase over the third quarter of 2012 is due to increased revenues due to gas liquids sold and gas sold primarily due to increased prices somewhat offset by higher cost of gas purchased. Total operating cost for our mid-stream segment for the third quarter of 2013 increased 6% over the second quarter of 2013 and increased 36% over the third quarter of 2012 due mainly to the cost of gas purchased.
After relocating two processing plants to our new Reno County, Kansas facility, our Hemphill County, Texas facility has the capacity to process 135 MMcf per day of our own and third party Granite Wash natural gas production. We are in the process of completing two pipeline extension projects for a total cost of approximately $5.7 million. These extensions will connect additional production from our oil and natural gas segment to this system.
We have completed initial construction of our new gathering system and processing facility in Reno County, Kansas.  This new system consists of approximately 20 miles of gathering pipeline and the two processing plants relocated from our Hemphill facility, a five MMcf per day refrigeration plant and a 20 MMcf per day turbo expander plant.  We began gathering gas at this facility during the second quarter and processing gas in the third quarter of 2013.

29


At our Cashion facility located in central Oklahoma, we completed the extension of our gathering system approximately three miles at a capital cost of $2.8 million.  This extension will allow us to gather additional production from active producers in the area.
In the Mississippian play in north central Oklahoma, our Bellmon system consists of approximately 142 miles of pipeline, which includes a 26 mile extension to connect our existing Remington plant, a 20 mile NGL line and two natural gas processing plants.  In the first quarter of 2013, we completed the installation of the second processing plant, a 30 MMcf per day cryogenic plant. This second plant is currently processing approximately 30 MMcf per day from third party producers in the area. Due to increasing volumes, we are in the process of installing an additional 60 MMcf per day processing plant.  This new cryogenic processing plant is expected to be operational in the fourth quarter of 2013.
 Our estimated 2013 capital expenditures for this segment are $96.0 million, excluding acquisitions. 
Financial Condition and Liquidity
Summary
Our financial condition and liquidity depends on the cash flow from our operations and borrowings under our credit agreement as well as the proceeds from our Notes. The principal factors determining the amount of 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 margins we obtain from our natural gas gathering and processing contracts.

The following is a summary of certain financial information as of September 30, 2013 and 2012 and for each of the nine months then ended:
 
September 30,
 
%
Change
 
2013
 
2012
 
 
(In thousands except percentages)
Working capital
$
(48,080
)
 
$
(37,363
)
 
(29
)%
Long-term debt
$
645,584

 
$
645,154

 
 %
Shareholders’ equity
$
2,116,945

 
$
2,028,976

 
4
 %
Ratio of long-term debt to total capitalization
23
%
 
24
%
 
(4
)%
Net income
$
133,445

 
$
79,723

 
67
 %
Net cash provided by operating activities
$
500,961

 
$
512,140

 
(2
)%
Net cash used in investing activities
$
(422,658
)
 
$
(888,597
)
 
(52
)%
Net cash provided by (used in) financing activities
$
(77,536
)
 
$
376,645

 
(121
)%

30


The following table summarizes certain operating information:
 
Nine Months Ended
September 30,
 
%
Change
 
2013
 
2012
 
Oil and Natural Gas:
 
 
 
 
 
Oil production (MBbls)
2,470

 
2,367

 
4
 %
Natural gas liquids production (MBbls)
2,758

 
2,014

 
37
 %
Natural gas production (MMcf)
42,411

 
34,403

 
23
 %
Average oil price per barrel received
$95.20
 
$92.96
 
2
 %
Average oil price per barrel received excluding hedges
$95.49
 
$91.93
 
4
 %
Average NGLs price per barrel received
$30.87
 
$30.70
 
1
 %
Average NGLs price per barrel received excluding hedges
$30.87
 
$29.61
 
4
 %
Average natural gas price per mcf received
$3.35
 
$3.26
 
3
 %
Average natural gas price per mcf received excluding hedges
$3.38
 
$2.29
 
48
 %
Contract Drilling:
 
 
 
 
 
Average number of our drilling rigs in use during the period
65.0

 
77.2

 
(16
)%
Total number of drilling rigs owned at the end of the period
124

 
127

 
(2
)%
Average dayrate
$19,651
 
$19,982
 
(2
)%
Mid-Stream:
 
 
 
 
 
Gas gathered—Mcf/day
308,645

 
240,318

 
28
 %
Gas processed—Mcf/day
137,725

 
134,799

 
2
 %
Gas liquids sold—gallons/day
505,584

 
576,358

 
(12
)%
Number of natural gas gathering systems
39

 
40

 
(3
)%
Number of processing plants
15

 
13

 
15
 %
At September 30, 2013, we had unrestricted cash totaling $1.7 million and had borrowed none of the $500.0 million we had elected to have available under our credit agreement. Our credit agreement is used primarily for working capital and capital expenditures.
On May 18, 2011, we completed the registered sale of $250.0 million aggregate principal amount of 6.625% Senior Subordinated Notes (the 2011 Notes) due 2021. The 2011 Notes were issued at par and mature on May 15, 2021. The net proceeds were used to repay outstanding borrowings under our credit agreement, which had $220.3 million outstanding as of May 18, 2011. The remaining proceeds were used for general working capital purposes.
On July 24, 2012, we completed the sale of $400.0 million aggregate principal amount of senior subordinated notes (the 2012 Notes) due May 15, 2021, bearing interest at a rate of 6.625% per year. The 2012 Notes were sold at 98.75% of par plus accrued interest from May 15, 2012. We used the net proceeds from the offering to partially finance our acquisition of certain oil and natural gas properties. We incurred $8.7 million of fees that are being amortized as debt issuance cost over the life of the 2012 Notes.
On November 13, 2012, we registered an offer with the SEC on Form S-4 to exchange the 2012 Notes for additional notes with materially identical terms to our existing registered 2011 Notes. On January 7, 2013, the exchange of the 2012 Notes was completed. The notes issued in exchange for all the 2012 Notes are now registered and are treated as a single series of debt securities with the 2011 Notes, resulting in a total of $650.0 million aggregate principal amount of 6.625% senior subordinated notes (the Notes). The interest of the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year, and the Notes will mature on May 15, 2021.
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 hedging activity. We had negative working capital of $48.1 million and $37.4 million, respectively, as of September 30, 2013 and 2012. The effect of our hedging activity decreased working capital by $1.4 million as of September 30, 2013 and increased working capital by $8.3 million as of September 30, 2012.

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Impact of Prices for Our Oil, NGLs, and Natural Gas
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 world oil market developments. All of these factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive.
Based on our first nine months of 2013 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of hedging, would result in a corresponding $450,000 per month ($5.4 million annualized) change in our pre-tax operating cash flow. The average price we received for our natural gas production, including the effect of hedging, during the first nine months of 2013 was $3.35 compared to $3.26 for the first nine months of 2012. Based on our first nine months of 2013 production, a $1.00 per barrel change in our oil price, without the effect of hedging, would have a $264,000 per month ($3.2 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 hedging, would have a $292,000 per month ($3.5 million annualized) change in our pre-tax operating cash flow. In the first nine months of 2013, our average oil price per barrel received, including the effect of hedging, was $95.20 compared with an average oil price, including the effect of hedging, of $92.96 in the first nine months of 2012 and our first nine months of 2013 average NGLs price per barrel received, including the effect of hedging, was $30.87 compared with an average NGLs price per barrel of $30.70 in the first nine months of 2012.
Because commodity prices effect the value of our oil, NGLs, and natural gas reserves, declines in those prices can result in a decline in the carrying value of our oil and natural gas properties. At September 30, 2013, the 12-month average unescalated prices were $95.08 per barrel of oil, $38.98 per barrel of NGLs, and $3.61 per Mcf of natural gas, then adjusted for price differentials. We were not required to take a write-down in the third quarter of 2013. If there are declines in the 12-month average prices, including the discounted value of our cash flow hedges, we may be required to record write-downs in future periods.
In the second quarter of 2012, the unamortized cost of our oil and natural gas properties exceeded the ceiling of our proved oil, NGLs, and natural gas reserves. As a result, we recorded a non-cash ceiling test write down of $115.9 million pre-tax ($72.1 million, net of tax). At September 30, 2012, the 12-month average unescalated prices were $94.97 per barrel of oil, $48.85 per barrel of NGLs, and $2.83 per Mcf of natural gas, adjusted for price differentials.
Price declines can also adversely affect the semi-annual determination 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.
Our natural gas production is sold to intrastate and interstate pipelines as well as to independent marketing firms and gatherers under contracts with terms generally ranging anywhere from one month to five years. Our oil production is sold to independent marketing firms generally in six month increments.
Contract Drilling

Many factors influence the number of drilling rigs we are working at any given time as well as 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. With the weakening of natural gas prices over the last several years the demand for drilling rigs in our contract drilling segment shifted to drilling wells focused on oil and NGL production.  Today, almost all of our working drilling rigs are drilling horizontal or directional wells for oil and NGLs. Part of this shift included operators moving to shallower oil plays like the Mississippian play in northern Oklahoma and southern Kansas. These shallower plays tend to use drilling rigs with lower horsepower which have lower dayrates and margins.  As methods for drilling horizontal wells have improved, demand to drill deeper and longer horizontal wells are starting to once again strengthen demand for higher horsepower rigs. All of these factors ultimately affect the demand and mix of the type of drilling rigs used by our customers. For the first nine months of 2013, our average dayrate was $19,651 per day compared to $19,982 per day for the first nine months of 2012. The average number of our drilling rigs used in the first nine months of 2013 was 65.0 drilling rigs (51%) compared with 77.2 drilling rigs (61%) in the first nine months of 2012. Based on the average utilization of our drilling rigs during the first nine months of 2013, a $100 per day change in dayrates has a $6,500 per day ($2.4 million annualized) change in our pre-tax operating cash flow.
Our contract drilling segment provides drilling services for our oil and natural gas segment. Depending on the timing of those services, some of those services are deemed to be associated with the acquisition of an ownership interest in the property. Accordingly, revenues and expenses for those drilling services are eliminated in our income statement, with any profit

32


recognized as a reduction in our investment in our oil and natural gas properties. The drilling contracts used for these services are issued under the same conditions and rates as the drilling contracts entered into with unrelated third parties. We eliminated revenue of $43.9 million and $37.7 million for the nine months of 2013 and 2012, respectively, from our contract drilling segment and eliminated the associated operating expense of $32.2 million and $24.8 million during the nine months of 2013 and 2012, respectively, yielding $11.7 million and $12.9 million during the nine months of 2013 and 2012, respectively, as a reduction to the carrying value of our oil and natural gas properties.
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, 15 processing plants, 39 gathering systems, and approximately 1,435 miles of pipeline. It operates in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. This segment enhances our ability to gather and market not only our own natural gas and NGLs but also that owned by third parties and serves as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first nine months of 2013 and 2012, this segment purchased $62.6 million and $47.5 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $5.7 million and $3.0 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 308,645 Mcf per day in the first nine