10-Q 1 pten-10q_20140930.htm 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

R | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

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 0-22664

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)

DELAWARE |  | 75-2504748
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)
450 GEARS ROAD, SUITE 500 HOUSTON, TEXAS |  | 77067
(Address of principal executive offices) |  | (Zip Code)

(281) 765-7100

(Registrant’s telephone number, including area code)

N/A

(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 R 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 (section 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 R 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:

Large accelerated filer |  | R |  | 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 R

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

146,412,860 shares of common stock, $0.01 par value, as of October 22, 2014

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

|  | PART I — FINANCIAL INFORMATION |  |
|  |  |  | Page
ITEM 1. |  | Financial Statements |  |
|  | Unaudited consolidated condensed balance sheets |  | 3
|  | Unaudited consolidated condensed statements of operations |  | 4
|  | Unaudited consolidated condensed statements of comprehensive income |  | 5
|  | Unaudited consolidated condensed statement of changes in stockholders’ equity |  | 6
|  | Unaudited consolidated condensed statements of cash flows |  | 7
|  | Notes to unaudited consolidated condensed financial statements |  | 8
ITEM 2. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations |  | 20
ITEM 3. |  | Quantitative and Qualitative Disclosures About Market Risk |  | 31
ITEM 4. |  | Controls and Procedures |  | 31
|  | PART II — OTHER INFORMATION |  |
ITEM 1. |  | Legal Proceedings |  | 31
ITEM 2. |  | Unregistered Sales of Equity Securities and Use of Proceeds |  | 32
ITEM 6. |  | Exhibits |  | 32
Signature |  |  |  | 33

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

The following unaudited consolidated condensed financial statements include all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the interim periods presented.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(unaudited, in thousands, except share data)

| September 30, |  |  | December 31, |
| 2014 |  |  | 2013 |
ASSETS |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |
Cash and cash equivalents | $ | 38,594 |  |  | $ | 249,509 |
Accounts receivable, net of allowance for doubtful accounts of $3,665 and $3,674 at September 30, 2014 and December 31, 2013, respectively |  | 593,373 |  |  |  | 451,517 |
Inventory |  | 29,162 |  |  |  | 21,248 |
Deferred tax assets, net |  | 32,322 |  |  |  | 32,952 |
Other |  | 54,645 |  |  |  | 53,424 |
Total current assets |  | 748,096 |  |  |  | 808,650 |
Property and equipment, net |  | 3,907,331 |  |  |  | 3,635,541 |
Goodwill and intangible assets |  | 180,223 |  |  |  | 167,470 |
Deposits on equipment purchases |  | 112,288 |  |  |  | 52,560 |
Other |  | 20,411 |  |  |  | 22,906 |
Total assets | $ | 4,968,349 |  |  | $ | 4,687,127 |
LIABILITIES AND STOCKHOLDERS' EQUITY |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |
Accounts payable | $ | 370,127 |  |  | $ | 173,150 |
Federal and state income taxes payable |  | 24,378 |  |  |  | 10,670 |
Accrued expenses |  | 182,944 |  |  |  | 160,457 |
Current portion of long-term debt |  | 10,000 |  |  |  | 10,000 |
Total current liabilities |  | 587,449 |  |  |  | 354,277 |
Long-term debt |  | 675,000 |  |  |  | 682,500 |
Deferred tax liabilities, net |  | 836,404 |  |  |  | 887,864 |
Other |  | 10,036 |  |  |  | 6,489 |
Total liabilities |  | 2,108,889 |  |  |  | 1,931,130 |
Commitments and contingencies (see Note 9) |  |  |  |  |  |  |
Stockholders' equity: |  |  |  |  |  |  |
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued |  | — |  |  | — |
Common stock, par value $.01; authorized 300,000,000 shares with 189,233,429 and 186,487,246 issued and 146,414,844 and 144,219,189 outstanding at September 30, 2014 and December 31, 2013, respectively |  | 1,892 |  |  |  | 1,865 |
Additional paid-in capital |  | 977,425 |  |  |  | 913,505 |
Retained earnings |  | 2,768,868 |  |  |  | 2,707,439 |
Accumulated other comprehensive income |  | 10,310 |  |  |  | 14,076 |
Treasury stock, at cost, 42,818,585 shares and 42,268,057 shares at September 30, 2014 and December 31, 2013, respectively |  | (899,035 | ) |  |  | (880,888 | )
Total stockholders' equity |  | 2,859,460 |  |  |  | 2,755,997 |
Total liabilities and stockholders' equity | $ | 4,968,349 |  |  | $ | 4,687,127 |

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

3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(unaudited, in thousands, except per share data)

| Three Months Ended |  |  | Nine Months Ended |
| September 30, |  |  | September 30, |
| 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Operating revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Contract drilling | $ | 482,212 |  |  | $ | 457,871 |  |  | $ | 1,346,698 |  |  | $ | 1,266,944 |
Pressure pumping |  | 348,692 |  |  |  | 259,209 |  |  |  | 895,530 |  |  |  | 744,989 |
Oil and natural gas |  | 14,724 |  |  |  | 13,827 |  |  |  | 38,844 |  |  |  | 45,329 |
Total operating revenues |  | 845,628 |  |  |  | 730,907 |  |  |  | 2,281,072 |  |  |  | 2,057,262 |
Operating costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Contract drilling |  | 278,195 |  |  |  | 239,768 |  |  |  | 784,572 |  |  |  | 729,588 |
Pressure pumping |  | 281,016 |  |  |  | 204,050 |  |  |  | 722,801 |  |  |  | 560,486 |
Oil and natural gas |  | 3,275 |  |  |  | 3,602 |  |  |  | 9,421 |  |  |  | 9,738 |
Depreciation, depletion, amortization and impairment |  | 237,825 |  |  |  | 140,734 |  |  |  | 538,573 |  |  |  | 414,351 |
Selling, general and administrative |  | 18,896 |  |  |  | 19,580 |  |  |  | 58,117 |  |  |  | 55,296 |
Net gain on asset disposals |  | (3,870 | ) |  |  | (1,378 | ) |  |  | (8,705 | ) |  |  | (2,286 | )
Total operating costs and expenses |  | 815,337 |  |  |  | 606,356 |  |  |  | 2,104,779 |  |  |  | 1,767,173 |
Operating income |  | 30,291 |  |  |  | 124,551 |  |  |  | 176,293 |  |  |  | 290,089 |
Other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest income |  | 234 |  |  |  | 293 |  |  |  | 618 |  |  |  | 716 |
Interest expense, net of amount capitalized |  | (6,993 | ) |  |  | (7,503 | ) |  |  | (21,430 | ) |  |  | (21,210 | )
Other |  | — |  |  |  | 380 |  |  |  | 3 |  |  |  | 780 |
Total other expense |  | (6,759 | ) |  |  | (6,830 | ) |  |  | (20,809 | ) |  |  | (19,714 | )
Income before income taxes |  | 23,532 |  |  |  | 117,721 |  |  |  | 155,484 |  |  |  | 270,375 |
Income tax expense (benefit): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current |  | 48,618 |  |  |  | 25,916 |  |  |  | 101,233 |  |  |  | 35,824 |
Deferred |  | (41,062 | ) |  |  | 17,385 |  |  |  | (50,830 | ) |  |  | 63,133 |
Total income tax expense |  | 7,556 |  |  |  | 43,301 |  |  |  | 50,403 |  |  |  | 98,957 |
Net income | $ | 15,976 |  |  | $ | 74,420 |  |  | $ | 105,081 |  |  | $ | 171,418 |
Net income per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic | $ | 0.11 |  |  | $ | 0.51 |  |  | $ | 0.72 |  |  | $ | 1.17 |
Diluted | $ | 0.11 |  |  | $ | 0.51 |  |  | $ | 0.71 |  |  | $ | 1.16 |
Weighted average number of common shares outstanding: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | 144,798 |  |  |  | 144,446 |  |  |  | 143,778 |  |  |  | 144,915 |
Diluted |  | 146,991 |  |  |  | 145,432 |  |  |  | 146,101 |  |  |  | 145,840 |
Cash dividends per common share | $ | 0.10 |  |  | $ | 0.05 |  |  | $ | 0.30 |  |  | $ | 0.15 |

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

4

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited, in thousands)

| Three Months Ended |  |  | Nine Months Ended |
| September 30, |  |  | September 30, |
| 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Net income | $ | 15,976 |  |  | $ | 74,420 |  |  | $ | 105,081 |  |  | $ | 171,418 |
Other comprehensive income (loss), net of taxes of $0 for all periods: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency translation adjustment |  | (4,899 | ) |  |  | 2,383 |  |  |  | (3,766 | ) |  |  | (3,668 | )
Total comprehensive income | $ | 11,077 |  |  | $ | 76,803 |  |  | $ | 101,315 |  |  | $ | 167,750 |

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

5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(unaudited, in thousands)

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Accumulated |  |  |  |  |  |  |  |  |
| Common Stock |  |  | Additional |  |  |  |  |  |  | Other |  |  |  |  |  |  |  |  |
| Number of |  |  |  |  |  |  | Paid-in |  |  | Retained |  |  | Comprehensive |  |  | Treasury |  |  |  |  |
| Shares |  |  | Amount |  |  | Capital |  |  | Earnings |  |  | Income |  |  | Stock |  |  | Total |
Balance, December 31, 2013 |  | 186,487 |  |  | $ | 1,865 |  |  | $ | 913,505 |  |  | $ | 2,707,439 |  |  | $ | 14,076 |  |  | $ | (880,888 | ) |  |  | 2,755,997 |
Net income | — |  |  | — |  |  | — |  |  |  | 105,081 |  |  | — |  |  | — |  |  |  | 105,081 |
Foreign currency translation adjustment | — |  |  | — |  |  | — |  |  | — |  |  |  | (3,766 | ) |  | — |  |  |  | (3,766 | )
Issuance of restricted stock |  | 1,067 |  |  |  | 11 |  |  |  | (11 | ) |  | — |  |  | — |  |  | — |  |  | — |
Vesting of stock unit awards |  | 10 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Forfeitures of restricted stock |  | (46 | ) |  |  | (1 | ) |  |  | 1 |  |  | — |  |  | — |  |  | — |  |  |  | — |
Exercise of stock options |  | 1,715 |  |  |  | 17 |  |  |  | 35,303 |  |  | — |  |  | — |  |  | — |  |  |  | 35,320 |
Stock-based compensation | — |  |  | — |  |  |  | 19,945 |  |  | — |  |  | — |  |  | — |  |  |  | 19,945 |
Tax benefit related to stock-based compensation | — |  |  | — |  |  |  | 8,682 |  |  | — |  |  | — |  |  | — |  |  |  | 8,682 |
Payment of cash dividends | — |  |  | — |  |  | — |  |  |  | (43,652 | ) |  | — |  |  | — |  |  |  | (43,652 | )
Purchase of treasury stock | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  |  | (18,147 | ) |  |  | (18,147 | )
Balance, September 30, 2014 |  | 189,233 |  |  | $ | 1,892 |  |  | $ | 977,425 |  |  | $ | 2,768,868 |  |  | $ | 10,310 |  |  | $ | (899,035 | ) |  | $ | 2,859,460 |

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

6

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

| Nine Months Ended |
| September 30, |
| 2014 |  |  | 2013 |
Cash flows from operating activities: |  |  |  |  |  |  |
Net income | $ | 105,081 |  |  | $ | 171,418 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |
Depreciation, depletion, amortization and impairment |  | 538,573 |  |  |  | 414,351 |
Dry holes and abandonments |  | 337 |  |  |  | 54 |
Deferred income tax (benefit) expense |  | (50,830 | ) |  |  | 63,133 |
Stock-based compensation expense |  | 19,945 |  |  |  | 19,028 |
Net gain on asset disposals |  | (8,705 | ) |  |  | (2,286 | )
Changes in operating assets and liabilities: |  |  |  |  |  |  |
Accounts receivable |  | (143,039 | ) |  |  | (23,662 | )
Income taxes payable |  | 13,701 |  |  |  | (5,586 | )
Inventory and other assets |  | (6,419 | ) |  |  | 3,090 |
Accounts payable |  | 71,865 |  |  |  | 22,207 |
Accrued expenses |  | 22,414 |  |  |  | (4,895 | )
Other liabilities |  | 3,410 |  |  |  | (152 | )
Net cash provided by operating activities |  | 566,333 |  |  |  | 656,700 |
Cash flows from investing activities: |  |  |  |  |  |  |
Purchases of property and equipment and acquisitions |  | (773,791 | ) |  |  | (483,284 | )
Proceeds from disposal of assets |  | 22,499 |  |  |  | 8,282 |
Net cash used in investing activities |  | (751,292 | ) |  |  | (475,002 | )
Cash flows from financing activities: |  |  |  |  |  |  |
Purchases of treasury stock |  | (13,554 | ) |  |  | (73,406 | )
Dividends paid |  | (43,652 | ) |  |  | (21,904 | )
Tax benefit related to stock-based compensation |  | 8,682 |  |  |  | 4,791 |
Repayment of long-term debt |  | (7,500 | ) |  |  | (3,750 | )
Proceeds from exercise of stock options |  | 30,726 |  |  |  | 6,959 |
Net cash used in financing activities |  | (25,298 | ) |  |  | (87,310 | )
Effect of foreign exchange rate changes on cash |  | (658 | ) |  |  | (475 | )
Net increase (decrease) in cash and cash equivalents |  | (210,915 | ) |  |  | 93,913 |
Cash and cash equivalents at beginning of period |  | 249,509 |  |  |  | 110,723 |
Cash and cash equivalents at end of period | $ | 38,594 |  |  | $ | 204,636 |
Supplemental disclosure of cash flow information: |  |  |  |  |  |  |
Net cash paid during the period for: |  |  |  |  |  |  |
Interest, net of capitalized interest of $5,268 in 2014 and $6,016 in 2013 | $ | (13,678 | ) |  | $ | (12,703 | )
Income taxes | $ | (74,252 | ) |  | $ | (31,361 | )
Supplemental non-cash investing and financing information: |  |  |  |  |  |  |
Net increase (decrease) in current liabilities for purchases of property and equipment | $ | 125,271 |  |  | $ | (29,818 | )
Net (increase) decrease in deposits on equipment purchases | $ | (59,728 | ) |  | $ | 2,749 |

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

7

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

1. Basis of Consolidation and Presentation

The unaudited interim consolidated condensed financial statements include the accounts of Patterson-UTI Energy, Inc. (the “Company”) and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries, the Company has no controlling financial interests in any entity which would require consolidation.

The unaudited interim consolidated condensed financial statements have been prepared by management of the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although the Company believes the disclosures included either on the face of the financial statements or herein are sufficient to make the information presented not misleading. In the opinion of management, all adjustments which are of a normal recurring nature considered necessary for a fair statement of the information in conformity with accounting principles generally accepted in the United States of America have been included. The Unaudited Consolidated Condensed Balance Sheet as of December 31, 2013, as presented herein, was derived from the audited consolidated balance sheet of the Company, but does not include all disclosures required by accounting principles generally accepted in the United States of America. These unaudited consolidated condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013. The results of operations for the nine months ended September 30, 2014 are not necessarily indicative of the results to be expected for the full year.

The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian operations, which uses the Canadian dollar as its functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity.

The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value.

The Company provides a dual presentation of its net income per common share in its unaudited consolidated condensed statements of operations: Basic net income per common share (“Basic EPS”) and diluted net income per common share (“Diluted EPS”).

Basic EPS excludes dilution and is computed by first allocating earnings between common stockholders and holders of non-vested shares of restricted stock. Basic EPS is then determined by dividing the earnings attributable to common stockholders by the weighted average number of common shares outstanding during the period, excluding non-vested shares of restricted stock.

Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock and restricted stock units. The dilutive effect of stock options and restricted stock units is determined using the treasury stock method. The dilutive effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class method, assuming a reallocation of undistributed earnings to common stockholders after considering the dilutive effect of potential common shares other than non-vested shares of restricted stock.

8

The following table presents information necessary to calculate net income per share for the three and nine months ended September 30, 2014 and 2013 as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per share amounts):

| Three Months Ended |  |  | Nine Months Ended |
| September 30, |  |  | September 30, |
| 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
BASIC EPS: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income | $ | 15,976 |  |  | $ | 74,420 |  |  | $ | 105,081 |  |  | $ | 171,418 |
Adjust for income attributed to holders of non-vested restricted stock |  | (160 | ) |  |  | (808 | ) |  |  | (1,074 | ) |  |  | (1,660 | )
Income attributed to common stockholders | $ | 15,816 |  |  | $ | 73,612 |  |  | $ | 104,007 |  |  | $ | 169,758 |
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock |  | 144,798 |  |  |  | 144,446 |  |  |  | 143,778 |  |  |  | 144,915 |
Basic net income per common share | $ | 0.11 |  |  | $ | 0.51 |  |  | $ | 0.72 |  |  | $ | 1.17 |
DILUTED EPS: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income attributed to common stockholders | $ | 15,816 |  |  | $ | 73,612 |  |  | $ | 104,007 |  |  | $ | 169,758 |
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock |  | 144,798 |  |  |  | 144,446 |  |  |  | 143,778 |  |  |  | 144,915 |
Add dilutive effect of potential common shares |  | 2,193 |  |  |  | 986 |  |  |  | 2,323 |  |  |  | 925 |
Weighted average number of diluted common shares outstanding |  | 146,991 |  |  |  | 145,432 |  |  |  | 146,101 |  |  |  | 145,840 |
Diluted net income per common share | $ | 0.11 |  |  | $ | 0.51 |  |  | $ | 0.71 |  |  | $ | 1.16 |
Potentially dilutive securities excluded as anti-dilutive |  | 442 |  |  |  | 2,897 |  |  |  | 473 |  |  |  | 4,043 |

2. Stock-based Compensation

The Company uses share-based payments to compensate employees and non-employee directors. The Company recognizes the cost of share-based payments under the fair-value-based method. Share-based awards consist of equity instruments in the form of stock options, restricted stock or restricted stock units and have included service and, in certain cases, performance conditions. The Company’s share-based awards have also included both cash-settled and share-settled performance unit awards. Cash-settled performance unit awards are accounted for as liability awards. Share-settled performance unit awards are accounted for as equity awards. The Company issues shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units and share-settled performance unit awards vest.

On February 21, 2014, the Company’s Board of Directors adopted the Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan (the “2014 Plan”), subject to approval by the Company’s stockholders. In addition, on the same date, the Board of Directors approved, subject to and effective upon the approval by the stockholders of the 2014 Plan, the termination of any future grants under all existing equity plans of the Company. On April 17, 2014, the Company’s stockholders approved the 2014 Plan. The aggregate number of shares of Common Stock authorized for grant under the 2014 Plan is 9,100,000, reduced by the number of shares that were subject to awards granted under existing equity plans of the Company during the period commencing on January 1, 2014 and ending on the date the 2014 Plan was approved by the stockholders.

Stock Options — The Company estimates the grant date fair values of stock options using the Black-Scholes-Merton valuation model. Volatility assumptions are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the options as of the date the options are granted. The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the options are granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. Weighted-average assumptions used to estimate the grant date fair values for stock options granted for the three and nine month periods ended September 30, 2014 and 2013 follow:

| Three Months Ended |  | Nine Months Ended |
| September 30, |  | September 30, |
| 2014 |  |  | 2013 |  | 2014 |  |  | 2013 |
Volatility |  | 35.64 | % |  | NA |  |  | 35.89 | % |  |  | 41.36 | %
Expected term (in years) |  | 5.00 |  |  | NA |  |  | 5.00 |  |  |  | 5.00 |
Dividend yield |  | 1.18 | % |  | NA |  |  | 1.17 | % |  |  | 0.89 | %
Risk-free interest rate |  | 1.62 | % |  | NA |  |  | 1.76 | % |  |  | 0.70 | %

9

Stock option activity from January 1, 2014 to September 30, 2014 follows:

|  |  |  |  | Weighted |
|  |  |  |  | Average |
| Underlying |  |  | Exercise |
| Shares |  |  | Price |
Outstanding at January 1, 2014 |  | 7,319,695 |  |  | $ | 21.23 |
Granted |  | 491,750 |  |  | $ | 32.32 |
Exercised |  | (1,715,195 | ) |  | $ | 20.59 |
Cancelled |  | — |  |  | $ | — |
Expired |  | — |  |  | $ | — |
Outstanding at September 30, 2014 |  | 6,096,250 |  |  | $ | 22.30 |
Exercisable at September 30, 2014 |  | 5,117,764 |  |  | $ | 21.48 |

Restricted Stock — For all restricted stock awards to date, shares of common stock were issued when the awards were made. Non-vested shares are subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Non-forfeitable dividends are paid on non-vested shares of restricted stock. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period.

Restricted stock activity from January 1, 2014 to September 30, 2014 follows:

|  |  |  |  | Weighted |
|  |  |  |  | Average |
|  |  |  |  | Grant Date |
| Shares |  |  | Fair Value |
Non-vested restricted stock outstanding at January 1, 2014 |  | 1,496,692 |  |  | $ | 20.84 |
Granted |  | 778,100 |  |  | $ | 33.40 |
Vested |  | (713,210 | ) |  | $ | 21.75 |
Forfeited |  | (45,616 | ) |  | $ | 23.43 |
Non-vested restricted stock outstanding September 30, 2014 |  | 1,515,966 |  |  | $ | 26.79 |

Restricted Stock Units — For all restricted stock unit awards made to date, shares of common stock are not issued until the units vest. Restricted stock units are subject to forfeiture for failure to fulfill service conditions. Non-forfeitable cash dividend equivalents are paid on certain non-vested restricted stock units. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period.

Restricted stock unit activity from January 1, 2014 to September 30, 2014 follows:

|  |  |  |  | Weighted |
|  |  |  |  | Average |
|  |  |  |  | Grant Date |
| Shares |  |  | Fair Value |
Non-vested restricted stock units outstanding at January 1, 2014 |  | 20,256 |  |  | $ | 20.67 |
Granted |  | 21,550 |  |  | $ | 34.67 |
Vested |  | (9,754 | ) |  | $ | 22.13 |
Forfeited |  | (667 | ) |  | $ | 21.09 |
Non-vested restricted stock units outstanding September 30, 2014 |  | 31,385 |  |  | $ | 29.82 |

Performance Unit Awards — In 2011, 2012, 2013 and 2014 the Company granted stock-settled performance unit awards to certain executive officers (the “Stock-Settled Performance Units”). The Stock-Settled Performance Units provide for the recipients to receive a grant of shares of stock upon the achievement of certain performance goals established by the Compensation Committee during the performance period. The performance period for the Stock-Settled Performance Units is the three year period commencing on April 1 of the year of grant. For the 2012 and 2013 Stock-Settled Performance Units, the performance period can extend for an additional two years in certain circumstances. The performance goals for the Stock-Settled Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee. These goals are considered to be market conditions under the relevant accounting standards and the market conditions were factored into the determination of the fair value of the performance units. Generally, the recipients will receive a target number of shares if the Company’s total shareholder return is positive and, when compared to the peer group, is at the 50 th percentile and two times the target if at the 75 th percentile or higher. If the Company’s total shareholder return is positive, and, when

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compared to the peer group, is at the 25 th percentile, the recipients will only receive one-half of the target number of shares. The grant of shares when achievement is between the 25 th and 75 th percentile will be determined on a pro-rata basis. The target number of shares with respect to the 2011 Stock-Settled Performance Units was 144,375. The performance period for the 2011 Stock-Settled Performance Units ended on March 31, 2014, and the Company’s total shareholder return was at the 94 th percentile. In April 2014, 288,750 shares were issued to settle the 2011 Stock-Settled Performance Units.

The total target number of shares with respect to the Stock-Settled Performance Units is set forth below:

| 2014 |  |  | 2013 |  |  | 2012 |  |  | 2011 |
| Performance |  |  | Performance |  |  | Performance |  |  | Performance |
| Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |
Target number of shares |  | 154,000 |  |  |  | 236,500 |  |  |  | 192,000 |  |  |  | 144,375 |

Because the Stock-Settled Performance Units are stock-settled awards, they are accounted for as equity awards and measured at fair value on the date of grant using a Monte Carlo simulation model. The fair value of the Stock-Settled Performance Units is set forth below (in thousands):

| 2014 |  |  | 2013 |  |  | 2012 |  |  | 2011 |
| Performance |  |  | Performance |  |  | Performance |  |  | Performance |
| Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |
Fair value at date of grant | $ | 5,388 |  |  | $ | 5,564 |  |  | $ | 3,065 |  |  | $ | 5,569 |

These fair value amounts are charged to expense on a straight-line basis over the performance period. Compensation expense associated with the Stock-Settled Performance Units is shown below (in thousands):

| 2014 |  |  | 2013 |  |  | 2012 |  |  | 2011 |
| Performance |  |  | Performance |  |  | Performance |  |  | Performance |
| Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |
Three months ended September 30, 2013 | NA |  |  | $ | 464 |  |  | $ | 255 |  |  | $ | 464 |
Three months ended September 30, 2014 | $ | 449 |  |  | $ | 464 |  |  | $ | 255 |  |  | NA |
Nine months ended September 30, 2013 | NA |  |  | $ | 927 |  |  | $ | 766 |  |  | $ | 1,392 |
Nine months ended September 30, 2014 | $ | 898 |  |  | $ | 1,391 |  |  | $ | 766 |  |  | $ | 464 |

3. Property and Equipment

Property and equipment consisted of the following at September 30, 2014 and December 31, 2013 (in thousands):

| September 30, |  |  | December 31, |
| 2014 |  |  | 2013 |
Equipment | $ | 6,361,452 |  |  | $ | 5,749,975 |
Oil and natural gas properties |  | 207,340 |  |  |  | 183,571 |
Buildings |  | 83,230 |  |  |  | 80,050 |
Land |  | 12,046 |  |  |  | 12,054 |
|  | 6,664,068 |  |  |  | 6,025,650 |
Less accumulated depreciation and depletion |  | (2,756,737 | ) |  |  | (2,390,109 | )
Property and equipment, net | $ | 3,907,331 |  |  | $ | 3,635,541 |

During the period ended September 30, 2014, in connection with its ongoing planning process, the Company evaluated its fleet of marketable drilling rigs and identified 55 mechanical rigs that it determined would no longer be marketed. The Company’s consolidated statements of operations includes a charge of $77.9 million related to the Company’s mechanically powered rig fleet. This charge reflects the retirement of the 55 mechanical drilling rigs and the write-off of excess spare components for the now reduced size of the Company’s mechanical rig fleet.

4. Business Segments

The Company’s revenues, operating profits and identifiable assets are primarily attributable to three business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) the investment, on a non-operating working interest basis, in oil and natural gas properties. Each of these segments represents a distinct type of business. These segments have

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separate management teams which report to the Company’s chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. Separate financial data for each of our business segments is provided in the table below (in thousands):

| Three Months Ended |  |  | Nine Months Ended |
| September 30, |  |  | September 30, |
| 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Contract drilling | $ | 483,307 |  |  | $ | 459,213 |  |  | $ | 1,350,296 |  |  | $ | 1,270,658 |
Pressure pumping |  | 349,996 |  |  |  | 259,209 |  |  |  | 896,834 |  |  |  | 744,989 |
Oil and natural gas |  | 14,724 |  |  |  | 13,827 |  |  |  | 38,844 |  |  |  | 45,329 |
Total segment revenues |  | 848,027 |  |  |  | 732,249 |  |  |  | 2,285,974 |  |  |  | 2,060,976 |
Elimination of intercompany revenues (a) |  | (2,399 | ) |  |  | (1,342 | ) |  |  | (4,902 | ) |  |  | (3,714 | )
Total revenues | $ | 845,628 |  |  | $ | 730,907 |  |  | $ | 2,281,072 |  |  | $ | 2,057,262 |
Income before income taxes: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Contract drilling | $ | 12,147 |  |  | $ | 116,253 |  |  | $ | 148,841 |  |  | $ | 235,871 |
Pressure pumping |  | 25,208 |  |  |  | 16,917 |  |  |  | 51,661 |  |  |  | 75,686 |
Oil and natural gas |  | 3,002 |  |  |  | 5,421 |  |  |  | 9,337 |  |  |  | 17,189 |
|  | 40,357 |  |  |  | 138,591 |  |  |  | 209,839 |  |  |  | 328,746 |
Corporate and other |  | (13,936 | ) |  |  | (15,418 | ) |  |  | (42,251 | ) |  |  | (40,943 | )
Net gain on asset disposals (b) |  | 3,870 |  |  |  | 1,378 |  |  |  | 8,705 |  |  |  | 2,286 |
Interest income |  | 234 |  |  |  | 293 |  |  |  | 618 |  |  |  | 716 |
Interest expense |  | (6,993 | ) |  |  | (7,503 | ) |  |  | (21,430 | ) |  |  | (21,210 | )
Other |  | — |  |  |  | 380 |  |  |  | 3 |  |  |  | 780 |
Income before income taxes | $ | 23,532 |  |  | $ | 117,721 |  |  | $ | 155,484 |  |  | $ | 270,375 |

| September 30, |  |  | December 31, |
| 2014 |  |  | 2013 |
Identifiable assets: |  |  |  |  |  |  |
Contract drilling | $ | 3,859,415 |  |  | $ | 3,569,588 |
Pressure pumping |  | 970,327 |  |  |  | 761,199 |
Oil and natural gas |  | 67,067 |  |  |  | 58,656 |
Corporate and other (c) |  | 71,540 |  |  |  | 297,684 |
Total assets | $ | 4,968,349 |  |  | $ | 4,687,127 |

(a) | Consists of contract drilling and, in 2014, pressure pumping intercompany revenues for services provided to the oil and natural gas exploration and production segment.

(b) | Net gains or losses associated with the disposal of assets relate to corporate strategy decisions of the executive management group. Accordingly, the related gains or losses have been separately presented and excluded from the results of specific segments.

(c) | Corporate and other assets primarily include cash on hand and certain deferred tax assets.

5. Goodwill and Intangible Assets

Goodwill — Goodwill by operating segment as of September 30, 2014 and changes for the nine months then ended are as follows (in thousands):

| Contract |  |  | Pressure |  |  |  |  |
| Drilling |  |  | Pumping |  |  | Total |
Balance December 31, 2013 | $ | 86,234 |  |  | $ | 67,575 |  |  | $ | 153,809 |
Changes to goodwill | — |  |  |  | 15,485 |  |  |  | 15,485 |
Balance September 30, 2014 | $ | 86,234 |  |  | $ | 83,060 |  |  | $ | 169,294 |

There were no accumulated impairment losses as of September 30, 2014 or December 31, 2013.

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Goodwill is evaluated at least annually on December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing have been determined to be its operating segments. The Company first determines whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. If so, then goodwill impairment is determined using a two-step impairment test. From time to time, the Company may perform the first step of the quantitative testing for goodwill impairment in lieu of performing the qualitative assessment. The first step is to compare the fair value of an entity’s reporting units to the respective carrying value of those reporting units. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment test is performed whereby the fair value of the reporting unit is allocated to its identifiable tangible and intangible assets and liabilities with any remaining fair value representing the fair value of goodwill. If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized in the amount of the shortfall.

Intangible Assets — Intangible assets were recorded in the pressure pumping operating segment in connection with the fourth quarter 2010 acquisition of the assets of a pressure pumping business. As a result of the purchase price allocation, the Company recorded intangible assets related to the customer relationships acquired and a non-compete agreement. These intangible assets were recorded at fair value on the date of acquisition.

The value of the customer relationships was estimated using a multi-period excess earnings model to determine the present value of the projected cash flows associated with the customers in place at the time of the acquisition and taking into account a contributory asset charge. The resulting intangible asset is being amortized on a straight-line basis over seven years. Amortization expense of approximately $911,000 was recorded in the three months ended September 30, 2014 and 2013 and amortization expense of approximately $2.7 million was recorded in the nine months ended September 30, 2014 and 2013 associated with customer relationships.

The following table presents the gross carrying amount and accumulated amortization of the customer relationships as of September 30, 2014 and December 31, 2013 (in thousands):

| September 30, 2014 |  |  | December 31, 2013 |
| Gross |  |  |  |  |  |  | Net |  |  | Gross |  |  |  |  |  |  | Net |
| Carrying |  |  | Accumulated |  |  | Carrying |  |  | Carrying |  |  | Accumulated |  |  | Carrying |
| Amount |  |  | Amortization |  |  | Amount |  |  | Amount |  |  | Amortization |  |  | Amount |
Customer relationships | $ | 25,500 |  |  | $ | (14,571 | ) |  | $ | 10,929 |  |  | $ | 25,500 |  |  | $ | (11,839 | ) |  | $ | 13,661 |

The non-compete agreement had a term of three years from October 1, 2010. The value of this agreement was estimated using a with and without scenario where cash flows were projected through the term of the agreement assuming this agreement was in place and compared to cash flows assuming the non-compete agreement was not in place. The intangible asset associated with the non-compete agreement was amortized on a straight-line basis over the three-year term of the agreement and was fully amortized by September 30, 2013. Amortization expense of approximately $117,000 was recorded in the three months ended September 30, 2013 and amortization expense of approximately $350,000 was recorded in the nine months ended September 30, 2013 associated with the non-compete agreement.

6. Accrued Expenses

Accrued expenses consisted of the following at September 30, 2014 and December 31, 2013 (in thousands):

| September 30, |  |  | December 31, |
| 2014 |  |  | 2013 |
Salaries, wages, payroll taxes and benefits | $ | 53,329 |  |  | $ | 45,836 |
Workers' compensation liability |  | 77,773 |  |  |  | 74,975 |
Property, sales, use and other taxes |  | 14,754 |  |  |  | 12,367 |
Insurance, other than workers' compensation |  | 11,177 |  |  |  | 10,129 |
Accrued interest payable |  | 13,713 |  |  |  | 7,604 |
Other |  | 12,198 |  |  |  | 9,546 |
| $ | 182,944 |  |  | $ | 160,457 |

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7. Asset Retirement Obligation

The Company records a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. This liability is included in the caption “other” in the liabilities section of the consolidated condensed balance sheet. The following table describes the changes to the Company’s asset retirement obligations during the nine months ended September 30, 2014 and 2013 (in thousands):

| Nine Months Ended |
| September 30, |
| 2014 |  |  | 2013 |
Balance at beginning of year | $ | 4,837 |  |  | $ | 4,422 |
Liabilities incurred |  | 411 |  |  |  | 276 |
Liabilities settled |  | (68 | ) |  |  | (119 | )
Accretion expense |  | 126 |  |  |  | 124 |
Revision in estimated costs of plugging oil and natural gas wells |  | 19 |  |  | — |
Asset retirement obligation at end of period | $ | 5,325 |  |  | $ | 4,703 |

8. Long Term Debt

Credit Facilities — On September 27, 2012, the Company entered into a Credit Agreement (the “Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders party thereto. The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility.

The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time. The revolving credit facility contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time.

The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments, which commenced December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments.

Subject to customary conditions, the Company may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility.

Loans under the Credit Agreement bear interest by reference, at the Company’s election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon the Company’s debt to capitalization ratio. As of September 30, 2014, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. A letter of credit fee is payable by the Company equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%.

Each domestic subsidiary of the Company other than immaterial subsidiaries has unconditionally guaranteed all existing and future indebtedness and liabilities of the other guarantors and the Company arising under the Credit Agreement and other loan documents. Such guarantees also cover obligations of the Company and any subsidiary of the Company arising under any interest rate swap contract with any person while such person is a lender under the Credit Agreement.

The Credit Agreement requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. The Company was in compliance with these covenants at September 30, 2014. The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants.

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Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require the Company to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy of the Company, such acceleration is automatic), and (iii) require the Company to cash collateralize any outstanding letters of credit.

As of September 30, 2014, the Company had $85.0 million principal amount outstanding under the term loan facility at an interest rate of 2.50% and no amounts outstanding under the revolving credit facility. The Company had $39.8 million in letters of credit outstanding at September 30, 2014 and, as a result, had available borrowing capacity of approximately $460 million at that date.

Senior Notes — On October 5, 2010, the Company completed the issuance and sale of $300 million in aggregate principal amount of its 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. The Company will pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020.

On June 14, 2012, the Company completed the issuance and sale of $300 million in aggregate principal amount of its 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. The Company will pay interest on the Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022.

The Series A Notes and Series B Notes are senior unsecured obligations of the Company which rank equally in right of payment with all other unsubordinated indebtedness of the Company. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of the existing domestic subsidiaries of the Company other than immaterial subsidiaries.

The Series A Notes and Series B Notes are prepayable at the Company’s option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. The Company must offer to prepay the notes upon the occurrence of any change of control. In addition, the Company must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.

The respective note purchase agreements require compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior fiscal quarters to interest charges for that same period. The Company was in compliance with these covenants at September 30, 2014.

Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if the Company defaults in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable.

Debt issuance costs are deferred and recognized as interest expense over the term of the underlying debt. Interest expense related to the amortization of debt issuance costs was approximately $547,000 for the three months ended September 30, 2014 and 2013 and approximately $1.6 million for the nine months ended September 30, 2014 and 2013.

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Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of September 30, 2014 (in thousands):

Year ending December 31, |  |  |
2014 | $ | 2,500 |
2015 |  | 12,500 |
2016 |  | 28,750 |
2017 |  | 41,250 |
2018 | — |
Thereafter |  | 600,000 |
Total | $ | 685,000 |

9. Commitments, Contingencies and Other Matters

As of September 30, 2014, the Company maintained letters of credit in the aggregate amount of $39.8 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of September 30, 2014, no amounts had been drawn under the letters of credit.

As of September 30, 2014, the Company had commitments to purchase approximately $574 million of major equipment for its drilling and pressure pumping businesses.

The Company’s pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. These agreements expire in 2016, 2017 and 2018. As of September 30, 2014, the remaining obligation under these agreements was approximately $72.0 million, of which materials with a total purchase price of approximately $200,000 were required to be purchased during the remainder of 2014. In the event that the required minimum quantities are not purchased during any contract year, the Company could be required to make a liquidated damages payment to the respective vendor for any shortfall.

In November 2011, the Company’s pressure pumping business entered into an agreement with a proppant vendor to advance up to $12.0 million to such vendor to finance the construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of September 30, 2014, advances of approximately $11.8 million had been made under this agreement and principal repayments of approximately $6.9 million had been received resulting in a balance outstanding of approximately $4.9 million.

In May 2013, the U.S. Equal Employment Opportunity Commission notified the Company of cause findings related to certain of its employment practices. The cause findings relate to allegations that the Company tolerated a hostile work environment for employees based on national origin and race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. The Company and the EEOC engaged in the statutory conciliation process. In March 2014, the EEOC notified us that this matter will be forwarded to its legal unit for litigation review. The Company believes that litigation will ensue. The Company intends to defend itself vigorously and, based on the information available to the Company at this time, the Company does not expect the outcome of this matter to have a material adverse effect on its financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter.

Other than the matter described above, the Company is party to various legal proceedings arising in the normal course of its business; the Company does not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on its financial condition, results of operations or cash flows.

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10. Stockholders’ Equity

Cash Dividends — The Company paid cash dividends during the nine months ended September 30, 2014 and 2013 as follows:

2013: | Per Share |  |  | Total |
|  |  |  |  | (in thousands) |
Paid on March 29, 2013 | $ | 0.05 |  |  | $ | 7,312 |
Paid on June 28, 2013 |  | 0.05 |  |  |  | 7,361 |
Paid on September 30, 2013 |  | 0.05 |  |  |  | 7,231 |
Total cash dividends | $ | 0.15 |  |  | $ | 21,904 |

2014: | Per Share |  |  | Total |
|  |  |  |  | (in thousands) |
Paid on March 27, 2014 | $ | 0.10 |  |  | $ | 14,456 |
Paid on June 26, 2014 |  | 0.10 |  |  |  | 14,562 |
Paid on September 24, 2014 |  | 0.10 |  |  |  | 14,634 |
Total cash dividends | $ | 0.30 |  |  | $ | 43,652 |

On October 22, 2014, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.10 per share to be paid on December 24, 2014 to holders of record as of December 10, 2014. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors.

On September 6, 2013, the Company’s Board of Directors approved a stock buyback program that authorizes purchase of up to $200 million of the Company’s common stock in open market or privately negotiated transactions. As of September 30, 2014, the Company had remaining authorization to purchase approximately $187 million of the Company’s outstanding common stock under the stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock.

The Company acquired 536,630 shares of treasury stock from employees during the nine months ended September 30, 2014. Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options. The remainder of these shares was acquired to satisfy payroll tax withholding obligations upon the exercise of stock options, the settlement of performance unit awards and the vesting of restricted stock. The total fair market value of these shares was approximately $17.7 million. These shares were acquired pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”) or the 2014 Plan and not pursuant to the stock buyback program.

Treasury stock acquisitions during the nine months ended September 30, 2014 were as follows (dollars in thousands):

| September 30, 2014 |
| Shares |  |  | Cost |
Treasury shares at beginning of period |  | 42,268,057 |  |  | $ | 880,888 |
Acquisitions pursuant to long-term incentive plans |  | 536,630 |  |  |  | 17,681 |
Purchases pursuant to the 2013 buyback program |  | 13,898 |  |  |  | 466 |
Treasury shares at end of period |  | 42,818,585 |  |  | $ | 899,035 |

11. Income Taxes

The Company’s effective income tax rate was 32.4% for the nine months ended September 30, 2014, compared to 36.6% for the nine months ended September 30, 2013. The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008), and allows a deduction of 9% on the lesser of qualified production activities income or taxable income. The prior year Domestic Production Activities Deduction was smaller due to lower taxable income after the utilization of bonus depreciation and a federal net operating loss carryforward. In 2014, the Company does not have any remaining federal net operating loss carryforward, and bonus depreciation is currently unavailable, resulting in higher taxable income and, therefore, a larger Domestic Production Activities Deduction.

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12. Fair Values of Financial Instruments

The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items. These fair value estimates are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting.

The estimated fair value of the Company’s outstanding debt balances (including current portion) as of September 30, 2014 and December 31, 2013 is set forth below (in thousands):

| September 30, 2014 |  |  | December 31, 2013 |
| Carrying |  |  | Fair |  |  | Carrying |  |  | Fair |
| Value |  |  | Value |  |  | Value |  |  | Value |
Borrowings under credit agreement: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Term loan facility | $ | 85,000 |  |  | $ | 85,000 |  |  | $ | 92,500 |  |  | $ | 92,500 |
4.97% Series A Senior Notes |  | 300,000 |  |  |  | 319,834 |  |  |  | 300,000 |  |  |  | 304,293 |
4.27% Series B Senior Notes |  | 300,000 |  |  |  | 304,893 |  |  |  | 300,000 |  |  |  | 286,772 |
Total debt | $ | 685,000 |  |  | $ | 709,727 |  |  | $ | 692,500 |  |  | $ | 683,565 |

The carrying values of the balances outstanding under the term loan approximate their fair values as this instrument has a floating interest rate. The fair value of the 4.97% Series A Senior Notes and the 4.27% Series B Senior Notes at September 30, 2014 and December 31, 2013 are based on discounted cash flows associated with the respective notes using current market rates of interest at those respective dates. For the 4.97% Series A Senior Notes, the current market rates used in measuring this fair value were 3.73% at September 30, 2014 and 4.52% at December 31, 2013. For the 4.27% Series B Senior Notes, the current market rates used in measuring this fair value was 4.02% at September 30, 2014 and 4.89% at December 31, 2013. These fair value estimates are based on observable market inputs and are considered Level 2 fair value estimates in the fair value hierarchy of fair value accounting.

13. Recently Issued Accounting Standards

In May 2014, the FASB issued an accounting standards update to provide guidance on the recognition of revenue from customers. Under this guidance, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects in exchange for the goods or services. This guidance also requires more detailed disclosures to enable users of the financial statements to understand the nature, amount, timing and uncertainty, if any, of revenue and cash flows arising from contracts with customers. The requirements in this update are effective during interim and annual periods beginning after December 15, 2016. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements.

In June 2014, the FASB issued an accounting standards update to provide guidance on the accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. The guidance requires that a performance target that affects vesting and that could be achieved after the requisite service period is treated as a performance condition. The requirements in this update are effective during interim and annual periods beginning after December 15, 2015. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.

14. Subsequent Event

On October 20, 2014, a subsidiary of the Company completed the acquisition of the Texas-based pressure pumping assets of a privately held company. This acquisition includes 148,250 horsepower of hydraulic fracturing equipment and provides the Company with two additional bases of operations and employees to support customer activity in South Texas and East Texas. The purchase price for the transaction was paid in cash. The Company is in the process of determining the fair values of the assets acquired and liabilities assumed and the results of operations of these assets will be included in the Company’s consolidated results of operations beginning in the quarter ending December 31, 2014. Certain required disclosures related to fair value and pro forma financial information are omitted from this document due to the initial accounting being incomplete as of the filing date.

The Company has completed two pressure pumping acquisitions this year, adding a total of approximately 180,000 horsepower to the fleet as well as three associated facilities and employees. In total, the Company has paid $176 million for these two acquisitions plus the assumption of property leases and other contractual obligations.

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DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Report”) and other public filings and press releases by us contain “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; revenue and cost expectations and backlog; financing of operations; oil and natural gas prices; source and sufficiency of funds required for building new equipment and additional acquisitions (if further opportunities arise); impact of inflation; demand for our services; competition; equipment availability; government regulation; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts and often use words such as “believes,” “budgeted,” “continue,” “expects,” “estimates,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” or the negative thereof and other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Forward-looking statements may be made orally or in writing, including, but not limited to, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act.

Forward-looking statements are not guarantees of future performance and a variety of factors could cause actual results to differ materially from the anticipated or expected results expressed in or suggested by these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates, utilization, margins and planned capital expenditures, global economic conditions, excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction, equipment specialization and new technologies, adverse credit and equity market conditions, difficulty in building and deploying new equipment and integrating acquisitions, shortages, delays in delivery and interruptions in supply of equipment, supplies and materials, weather, loss of key customers, liabilities from operations for which we do not have and receive full indemnification or insurance, ability to effectively identify and enter new markets, governmental regulation, ability to realize backlog, ability to retain management and field personnel and other factors. Refer to “Risk Factors” contained in Part 1 of our Annual Report on Form 10-K for the year ended December 31, 2013 for a more complete discussion of these and other factors that might affect our performance and financial results. You are cautioned not to place undue reliance on any of our forward-looking statements. These forward-looking statements are intended to relay our expectations about the future, and speak only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, changes in internal estimates or otherwise, except as required by law.

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

Management Overview — We are a leading provider of services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and pressure pumping services. In addition to these services, we also invest, on a non-operating working interest basis, in oil and natural gas properties.

We operate land-based drilling rigs in oil and natural gas producing regions of the continental United States, Alaska, and western and northern Canada. There continues to be uncertainty with respect to the global economic environment, and crude oil and natural gas prices are volatile. During the third quarter of 2014, our average number of rigs operating in the United States was 209 compared to an average of 181 drilling rigs operating during the same period in 2013. During the third quarter of 2014, our average number of rigs operating in Canada was 10 compared to an average of eight drilling rigs operating during the third quarter of 2013.

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by expanding our areas of operation and improving the capabilities of our drilling fleet during the last several years. As of September 30, 2014, we had completed 139 APEX® rigs and made performance and safety improvements to existing high capacity rigs. We have plans to complete 30 additional new APEX® rigs during the four quarters ending September 2015. In connection with horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs. In June 2014, we acquired the East Texas-based pressure pumping operations of a privately held company. The acquisition included 31,500 horsepower of hydraulic fracturing equipment and provides us with a new base of operations and employees to support drilling programs in East Texas and Louisiana. As of September 30, 2014, we had more than 850,000 hydraulic horsepower in our pressure pumping fleet. In October 2014, we completed the acquisition of the Texas-based pressure pumping assets of a privately held company. The acquisition included 148,250 horsepower of hydraulic fracturing equipment, which was manufactured in 2011 and 2012, and provides us with two additional bases of operations and employees to support customer activity in South Texas and East Texas. Relatively low natural gas prices and the industry-wide addition of new pressure pumping equipment to the marketplace led to an excess supply of pressure pumping equipment in North America during the last few years.

We maintain a backlog of commitments for contract drilling revenues under term contracts, which we define as contracts with a fixed term of six months or more. Our backlog as of September 30, 2014 was approximately $1.74 billion. We expect approximately $342 million of our backlog to be realized in the remainder of 2014. We generally calculate our backlog by multiplying the day rate under our term drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to other fees such as for mobilization, demobilization and customer reimbursables, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, generally our term drilling contracts are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. For contracts that we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the day rate, for the period we expect to receive the lower rate.

For the three and nine months ended September 30, 2014 and 2013, our operating revenues consisted of the following (in thousands):

| Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
| 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Contract drilling | $ | 482,212 |  |  |  | 57 | % |  | $ | 457,871 |  |  |  | 63 | % |  | $ | 1,346,698 |  |  |  | 59 | % |  | $ | 1,266,944 |  |  |  | 62 | %
Pressure pumping |  | 348,692 |  |  |  | 41 | % |  |  | 259,209 |  |  |  | 35 | % |  |  | 895,530 |  |  |  | 39 | % |  |  | 744,989 |  |  |  | 36 | %
Oil and natural gas |  | 14,724 |  |  |  | 2 | % |  |  | 13,827 |  |  |  | 2 | % |  |  | 38,844 |  |  |  | 2 | % |  |  | 45,329 |  |  |  | 2 | %
| $ | 845,628 |  |  |  | 100 | % |  | $ | 730,907 |  |  |  | 100 | % |  | $ | 2,281,072 |  |  |  | 100 | % |  | $ | 2,057,262 |  |  |  | 100 | %

Generally, the profitability of our business is impacted most by two primary factors in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the third quarter of 2014, our average number of rigs operating was 209 in the United States and 10 in Canada compared to 181 in the United States and eight in Canada in the third quarter of 2013. Our average revenue per operating day was $24,010 in the third quarter of 2014 compared to $22,650 in the third quarter of 2013, excluding the early termination revenue discussed below. Consolidated net income for the third quarter of 2014 was $16.0 million compared to consolidated net income of $74.4 million for the third quarter of 2013. This decrease in consolidated net income is primarily due to a charge of $77.9 million related to the retirement of 55 mechanical drilling rigs and the write-off of excess spare components for the now reduced size of the Company’s mechanical rig fleet. Also, revenues in the third quarter of 2013 included early termination revenues totaling approximately $62.8 million related to the early contract termination for six rigs.

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when these commodity prices deteriorate, the demand for our services

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generally weakens, and we experience downward pressure on pricing for our services. In September 2014, our average number of rigs operating was 211 in the United States and 10 in Canada.

We are highly impacted by operational risks, competition, the availability of excess equipment, labor issues, weather and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” included in Part I of our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

As of September 30, 2014, we had approximately $161 million in working capital and approximately $460 million available under our $500 million revolving credit facility. From September 30, 2014 through October 23, 2014, we borrowed $170 million under our revolving credit facility, leaving approximately $290 million available as of October 23, 2014, which, together with our working capital and cash expected to be generated from operations should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we nevertheless think additional capital would be advisable to pursue growth opportunities, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility, debt financing and equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Commitments and Contingencies — As of September 30, 2014, we maintained letters of credit in the aggregate amount of $39.8 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of September 30, 2014, no amounts had been drawn under the letters of credit.

As of September 30, 2014, we had commitments to purchase approximately $574 million of major equipment for our drilling and pressure pumping businesses.

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. These agreements expire in 2016, 2017 and 2018. As of September 30, 2014, the remaining obligation under these agreements was approximately $72.0 million, of which materials with a total purchase price of approximately $200,000 were required to be purchased during the remainder of 2014. In the event that the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall.

In November 2011, our pressure pumping business entered into an agreement with a proppant vendor to advance up to $12.0 million to such vendor to finance its construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of September 30, 2014, advances of approximately $11.8 million had been made under this agreement and repayments of approximately $6.9 million had been received resulting in a balance outstanding of approximately $4.9 million.

In May 2013, the U.S. Equal Employment Opportunity Commission notified us of cause findings related to certain of our employment practices. The cause findings relate to allegations that we tolerated a hostile work environment for employees based on national origin and race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. We and the EEOC engaged in the statutory conciliation process. In March 2014, the EEOC notified us that this matter will be forwarded to its legal unit for litigation review. We believe that litigation will ensue. We intend to defend ourselves vigorously and, based on the information available to us at this time, we do not expect the outcome of this matter to have a material adverse effect on our financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter.

Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.

Description of Business — We conduct our contract drilling operations primarily in the continental United States, Alaska and western and northern Canada. We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian region. Pressure pumping services are primarily well stimulation and cementing for completion of new wells and remedial work on existing wells. We also invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas working interests are located primarily in Texas and New Mexico.

The North American oil and natural gas services industry is cyclical and at times experiences downturns in demand. During these periods, there have been substantially more drilling rigs and pressure pumping equipment available than necessary to meet demand. As a result, drilling and pressure pumping contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods.

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In addition, unconventional resource plays have substantially increased and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology drilling rigs has been hampered by their lack of capability to efficiently compete for this work. Other ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:

· | movement of drilling rigs from region to region,

· | reactivation of land-based drilling rigs, or

· | construction of new technology drilling rigs.

Construction of new technology drilling rigs has increased in recent years. The addition of new technology drilling rigs to the market, combined with a reduction in the drilling of vertical wells, has resulted in excess capacity of older technology drilling rigs. Similarly, the substantial increase in unconventional resource plays has led to higher demand for pressure pumping services, and there has been a significant increase in the construction of new pressure pumping equipment across the industry. As a result of relatively low natural gas prices and the construction of new equipment, there has been an excess of pressure pumping equipment available. In circumstances of excess capacity, providers of pressure pumping services have difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict either the future level of demand for our contract drilling or pressure pumping services or future conditions in the oil and natural gas contract drilling or pressure pumping businesses.

Critical Accounting Policies

In addition to established accounting policies, our consolidated condensed financial statements are impacted by certain estimates and assumptions made by management. No changes in our critical accounting policies have occurred since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

Liquidity and Capital Resources

As of September 30, 2014, we had working capital of $161 million, including cash and cash equivalents of $39 million, compared to working capital of $454 million and cash and cash equivalents of $250 million at December 31, 2013. The decrease in working capital at September 30, 2014, compared to December 31, 2013, is primarily due to the acquisition of pressure pumping assets and an acceleration of our program of building new drilling rigs.

During the nine months ended September 30, 2014, our sources of cash flow included:

— | $566 million from operating activities,

— | $39.4 million from the exercise of stock options and related tax benefits associated with stock-based compensation, and

— | $22.5 million in proceeds from the disposal of property and equipment.

During the nine months ended September 30, 2014, we used $43.7 million to pay dividends on our common stock, $13.6 million to acquire shares of our common stock, $7.5 million to repay long-term debt and $774 million:

— | to build new drilling rigs and pressure pumping equipment,

— | to make capital expenditures for the betterment and refurbishment of existing drilling rigs and pressure pumping equipment,

— | to acquire and procure equipment and facilities to support our drilling and pressure pumping operations, including the acquisition of an East Texas-based pressure pumping operation, and

— | to fund investments in oil and natural gas properties on a non-operating working interest basis.

We paid cash dividends during the nine months ended September 30, 2014 as follows:

| Per Share |  |  | Total |
|  |  |  |  | (in thousands) |
Paid on March 27, 2014 | $ | 0.10 |  |  | $ | 14,456 |
Paid on June 26, 2014 |  | 0.10 |  |  |  | 14,562 |
Paid on September 24, 2014 |  | 0.10 |  |  |  | 14,634 |
Total cash dividends | $ | 0.30 |  |  | $ | 43,652 |

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On October 22, 2014, our Board of Directors approved a cash dividend on our common stock in the amount of $0.10 per share to be paid on December 24, 2014 to holders of record as of December 10, 2014. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

On September 6, 2013, our Board of Directors approved a stock buyback program that authorizes purchase of up to $200 million of our common stock in open market or privately negotiated transactions. As of September 30, 2014, we had remaining authorization to purchase approximately $187 million of our outstanding common stock under the new stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock.

The Company acquired 536,630 shares of treasury stock from employees during the nine months ended September 30, 2014. Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options. The remainder of these shares was acquired to satisfy payroll tax withholding obligations upon the exercise of stock options, the settlement of performance unit awards and the vesting of restricted stock. The total fair market value of these shares was approximately $17.7 million. These shares were acquired pursuant to the terms of the 2005 Plan or the 2014 Plan and not pursuant to the stock buyback program.

Treasury stock acquisitions during the nine months ended September 30, 2014 were as follows (dollars in thousands):

| September 30, 2014 |
| Shares |  |  | Cost |
Treasury shares at beginning of period |  | 42,268,057 |  |  | $ | 880,888 |
Acquisitions pursuant to long-term incentive plans |  | 536,630 |  |  |  | 17,681 |
Purchases pursuant to the 2013 buyback program |  | 13,898 |  |  |  | 466 |
Treasury shares at end of period |  | 42,818,585 |  |  | $ | 899,035 |

On September 27, 2012, we entered into a Credit Agreement (the “Credit Agreement”). The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility.

The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time. The revolving credit facility contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time.

The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments, which commenced December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments.

Subject to customary conditions, we may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon our debt to capitalization ratio. As of September 30, 2014, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%.

Each of our domestic subsidiaries other than immaterial subsidiaries has unconditionally guaranteed all of our existing and future indebtedness and liabilities of the other guarantors arising under the Credit Agreement and other loan documents. Such guarantees also cover our obligations and those of any of our subsidiaries arising under any interest rate swap contract with any person while such person is a lender under the Credit Agreement.

The Credit Agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of EBITDA of the four

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prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of September 30, 2014. The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require us to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy, such acceleration is automatic), and (iii) require us to cash collateralize any outstanding letters of credit.

As of September 30, 2014, we had $85.0 million principal amount outstanding under the term loan facility at an interest rate of 2.50% and no amounts outstanding under the revolving credit facility. We had $39.8 million in letters of credit outstanding at September 30, 2014 and, as a result, we had available borrowing capacity of approximately $460 million at that date.

On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. We pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020.

On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. We pay interest on the Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022.

The Series A Notes and Series B Notes are senior unsecured obligations which rank equally in right of payment with all of our other unsubordinated indebtedness. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of our existing domestic subsidiaries other than immaterial subsidiaries.

The Series A Notes and Series B Notes are prepayable at our option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. We must offer to prepay the notes upon the occurrence of any change of control. In addition, we must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.

The respective note purchase agreements require compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of September 30, 2014. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if we default in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable.

As of September 30, 2014, we had approximately $161 million in working capital and approximately $460 million available under our $500 million revolving credit facility. From September 30, 2014 through October 23, 2014, we borrowed $170 million under our revolving credit facility, leaving approximately $290 million available as of October 23, 2014, which, together with our working capital and cash expected to be generated from operations should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we nevertheless think additional capital would be advisable to pursue growth opportunities, we believe we would be able to satisfy these needs through

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a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility, debt financing and equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Results of Operations

The following tables summarize operations by business segment for the three months ended September 30, 2014 and 2013:

Contract Drilling |  | 2014 |  |  | 2013 |  |  | % Change |
|  | (Dollars in thousands) |  |  |  |  |
Revenues |  | $ | 482,212 |  |  | $ | 457,871 |  |  |  | 5.3 | %
Direct operating costs |  |  | 278,195 |  |  |  | 239,768 |  |  |  | 16.0 | %
Margin (1) |  |  | 204,017 |  |  |  | 218,103 |  |  |  | (6.5 | )%
Selling, general and administrative |  |  | 1,213 |  |  |  | 814 |  |  |  | 49.0 | %
Depreciation, amortization and impairment |  |  | 190,657 |  |  |  | 101,036 |  |  |  | 88.7 | %
Operating income |  | $ | 12,147 |  |  | $ | 116,253 |  |  |  | (89.6 | )%
Operating days |  |  | 20,084 |  |  |  | 17,442 |  |  |  | 15.1 | %
Average revenue per operating day |  | $ | 24.01 |  |  | $ | 26.25 |  |  |  | (8.5 | )%
Average direct operating costs per operating day |  | $ | 13.85 |  |  | $ | 13.75 |  |  |  | 0.7 | %
Average margin per operating day (1) |  | $ | 10.16 |  |  | $ | 12.50 |  |  |  | (18.7 | )%
Average rigs operating |  |  | 218 |  |  |  | 190 |  |  |  | 14.7 | %
Capital expenditures |  | $ | 209,769 |  |  | $ | 111,659 |  |  |  | 87.9 | %

(1) | Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per operating day is defined as margin divided by operating days.

The increases in revenues and direct operating costs reflect the increase in the number of rigs operating. Also, revenues in 2013 included approximately $62.8 million of early termination revenues related to the early contract termination for six rigs. Average revenue per operating day and average margin per operating day were higher in 2013 due to the early termination revenues. Depreciation, amortization and impairment expense for 2014 includes a charge of $77.9 million related to the retirement of 55 mechanical drilling rigs and the write-off of excess spare components for the now reduced size of the Company’s mechanical rig fleet. There were no similar charges in 2013. The increase in depreciation expense also reflects significant capital expenditures incurred in recent years to add new rigs to the fleet. Capital expenditures were incurred in recent years to build new drilling rigs, to modify and upgrade existing drilling rigs and to acquire additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment.

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Pressure Pumping |  | 2014 |  |  | 2013 |  |  | % Change |
|  | (Dollars in thousands) |  |  |  |  |
Revenues |  | $ | 348,692 |  |  | $ | 259,209 |  |  |  | 34.5 | %
Direct operating costs |  |  | 281,016 |  |  |  | 204,050 |  |  |  | 37.7 | %
Margin (1) |  |  | 67,676 |  |  |  | 55,159 |  |  |  | 22.7 | %
Selling, general and administrative |  |  | 4,881 |  |  |  | 4,482 |  |  |  | 8.9 | %
Depreciation, amortization and impairment |  |  | 37,587 |  |  |  | 33,760 |  |  |  | 11.3 | %
Operating income |  | $ | 25,208 |  |  | $ | 16,917 |  |  |  | 49.0 | %
Fracturing jobs |  |  | 358 |  |  |  | 327 |  |  |  | 9.5 | %
Other jobs |  |  | 1,228 |  |  |  | 1,306 |  |  |  | (6.0 | )%
Total jobs |  |  | 1,586 |  |  |  | 1,633 |  |  |  | (2.9 | )%
Average revenue per fracturing job |  | $ | 913.88 |  |  | $ | 722.92 |  |  |  | 26.4 | %
Average revenue per other job |  | $ | 17.53 |  |  | $ | 17.47 |  |  |  | 0.3 | %
Average revenue per total job |  | $ | 219.86 |  |  | $ | 158.73 |  |  |  | 38.5 | %
Average direct operating costs per total job |  | $ | 177.19 |  |  | $ | 124.95 |  |  |  | 41.8 | %
Average margin per total job (1) |  | $ | 42.67 |  |  | $ | 33.78 |  |  |  | 26.3 | %
Margin as a percentage of revenues (1) |  |  | 19.4 | % |  |  | 21.3 | % |  |  | (8.9 | )%
Capital expenditures and acquisitions |  | $ | 65,620 |  |  | $ | 29,494 |  |  |  | 122.5 | %

(1) | Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues.

Revenues and direct operating costs increased due to an increase in the size of our jobs and the size of our pressure pumping fleet. Our customers have continued the development of unconventional reservoirs, resulting in an increase in larger multi-stage fracturing jobs associated therewith. In connection with the horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs, including the June 2014 acquisition of an East Texas-based pressure pumping operation. As a result, we have continued to experience an increase in the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed. Additionally, the average size of the multi-stage fracturing jobs has increased. Average revenue per fracturing job and average direct operating costs per total job increased as a result of this increase in the proportion of larger multi-stage fracturing jobs and the increased size of the jobs in 2014 as compared to 2013. Depreciation expense increased due to capital expenditures.

Oil and Natural Gas Production and Exploration |  | 2014 |  |  | 2013 |  |  | % Change |
|  | (Dollars in thousands) |  |  |  |  |
Revenues-Oil |  | $ | 13,299 |  |  | $ | 12,479 |  |  |  | 6.6 | %
Revenues - Natural gas and liquids |  |  | 1,425 |  |  |  | 1,348 |  |  |  | 5.7 | %
Revenues-Total |  |  | 14,724 |  |  |  | 13,827 |  |  |  | 6.5 | %
Direct operating costs |  |  | 3,275 |  |  |  | 3,602 |  |  |  | (9.1 | )%
Margin (1) |  |  | 11,449 |  |  |  | 10,225 |  |  |  | 12.0 | %
Depletion and impairment |  |  | 8,447 |  |  |  | 4,804 |  |  |  | 75.8 | %
Operating income |  | $ | 3,002 |  |  | $ | 5,421 |  |  |  | (44.6 | )%
Capital expenditures |  | $ | 9,489 |  |  | $ | 8,823 |  |  |  | 7.5 | %

(1) | Margin is defined as revenues less direct operating costs and excludes depletion and impairment.

Oil revenues increased primarily due to increased production from new wells, offset by production declines on existing wells and lower prices. Direct operating costs decreased due to lower exploration costs. Depletion and impairment expense in 2014 includes approximately $2.2 million of oil and natural gas property impairments compared to approximately $160,000 of oil and natural gas property impairments in 2013. Depletion expense also increased due to the addition of new wells.

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Corporate and Other |  | 2014 |  |  | 2013 |  |  | % Change |
|  | (Dollars in thousands) |  |  |  |  |
Selling, general and administrative |  | $ | 12,802 |  |  | $ | 14,284 |  |  |  | (10.4 | )%
Depreciation |  | $ | 1,134 |  |  | $ | 1,134 |  |  |  | — |
Net (gain) loss on asset disposals |  | $ | (3,870 | ) |  | $ | (1,378 | ) |  |  | 180.8 | %
Interest income |  | $ | 234 |  |  | $ | 293 |  |  |  | (20.1 | )%
Interest expense |  | $ | 6,993 |  |  | $ | 7,503 |  |  |  | (6.8 | )%
Other income (expense) |  | $ | — |  |  | $ | 380 |  |  |  | (100.0 | )%
Capital expenditures |  | $ | 875 |  |  | $ | 755 |  |  |  | 15.9 | %

Selling, general and administrative expense in 2013 included approximately $1.7 million of expenses to evaluate and prepare for international growth opportunities. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. In 2014, the net gain on asset disposals resulted primarily from miscellaneous sales of drilling equipment.

The following tables summarize operations by business segment for the nine months ended September 30, 2014 and 2013:

Contract Drilling |  | 2014 |  |  | 2013 |  |  | % Change |
|  | (Dollars in thousands) |  |  |  |  |
Revenues |  | $ | 1,346,698 |  |  | $ | 1,266,944 |  |  |  | 6.3 | %
Direct operating costs |  |  | 784,572 |  |  |  | 729,588 |  |  |  | 7.5 | %
Margin (1) |  |  | 562,126 |  |  |  | 537,356 |  |  |  | 4.6 | %
Selling, general and administrative |  |  | 4,452 |  |  |  | 4,544 |  |  |  | (2.0 | )%
Depreciation, amortization and impairment |  |  | 408,833 |  |  |  | 296,941 |  |  |  | 37.7 | %
Operating income |  | $ | 148,841 |  |  | $ | 235,871 |  |  |  | (36.9 | )%
Operating days |  |  | 56,861 |  |  |  | 52,209 |  |  |  | 8.9 | %
Average revenue per operating day |  | $ | 23.68 |  |  | $ | 24.27 |  |  |  | (2.4 | )%
Average direct operating costs per operating day |  | $ | 13.80 |  |  | $ | 13.97 |  |  |  | (1.2 | )%
Average margin per operating day (1) |  | $ | 9.89 |  |  | $ | 10.29 |  |  |  | (3.9 | )%
Average rigs operating |  |  | 208 |  |  |  | 191 |  |  |  | 8.9 | %
Capital expenditures |  | $ | 546,609 |  |  | $ | 363,836 |  |  |  | 50.2 | %

(1) | Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per operating day is defined as margin divided by operating days.

The increases in revenues and direct operating costs reflect the increase in the number of rigs operating. Average revenue per operating day and average margin per operating day were higher in 2013 due to the early termination revenues of approximately $62.8 million related to the early contract termination for six rigs. Excluding the early contract termination revenue in 2013, average revenue per operating day and average margin per operating day would be higher in 2014 than in 2013 due to higher average pricing. Depreciation, amortization and impairment expense for 2014 includes a charge of $77.9 million related to the retirement of 55 mechanical drilling rigs and the write-off of excess spare components for mechanical rigs related to the now reduced size of the Company’s mechanical rig fleet. There were no similar charges during the period ended September 30, 2013. A charge of $37.8 million related to the Company’s mechanically powered rig fleet was recorded in the fourth quarter of 2013. The increase in depreciation expense also reflects significant capital expenditures incurred in recent years to add new rigs to the fleet. Capital expenditures were incurred in recent years to build new drilling rigs, to modify and upgrade existing drilling rigs and to acquire additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment.

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Pressure Pumping |  | 2014 |  |  | 2013 |  |  | % Change |
|  | (Dollars in thousands) |  |  |  |  |
Revenues |  | $ | 895,530 |  |  | $ | 744,989 |  |  |  | 20.2 | %
Direct operating costs |  |  | 722,801 |  |  |  | 560,486 |  |  |  | 29.0 | %
Margin (1) |  |  | 172,729 |  |  |  | 184,503 |  |  |  | (6.4 | )%
Selling, general and administrative |  |  | 14,816 |  |  |  | 13,032 |  |  |  | 13.7 | %
Depreciation, amortization and impairment |  |  | 106,252 |  |  |  | 95,785 |  |  |  | 10.9 | %
Operating income |  | $ | 51,661 |  |  | $ | 75,686 |  |  |  | (31.7 | )%
Fracturing jobs |  |  | 872 |  |  |  | 937 |  |  |  | (6.9 | )%
Other jobs |  |  | 3,166 |  |  |  | 3,635 |  |  |  | (12.9 | )%
Total jobs |  |  | 4,038 |  |  |  | 4,572 |  |  |  | (11.7 | )%
Average revenue per fracturing job |  | $ | 960.55 |  |  | $ | 724.06 |  |  |  | 32.7 | %
Average revenue per other job |  | $ | 18.30 |  |  | $ | 18.31 |  |  |  | (0.1 | )%
Average revenue per total job |  | $ | 221.78 |  |  | $ | 162.95 |  |  |  | 36.1 | %
Average direct operating costs per total job |  | $ | 179.00 |  |  | $ | 122.59 |  |  |  | 46.0 | %
Average margin per total job (1) |  | $ | 42.78 |  |  | $ | 40.35 |  |  |  | 6.0 | %
Margin as a percentage of revenues (1) |  |  | 19.3 | % |  |  | 24.8 | % |  |  | (22.2 | )%
Capital expenditures and acquisitions |  | $ | 198,103 |  |  | $ | 93,930 |  |  |  | 110.9 | %

(1) | Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues.

Revenues and direct operating costs increased due to an increase in the size of our jobs and the size of our pressure pumping fleet. Our customers have continued the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. In connection with the horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs, including the June 2014 acquisition of an East Texas-based pressure pumping operation. As a result, we have continued to experience an increase in the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed. Additionally, the average size of the multi-stage fracturing jobs has increased. Average revenue per fracturing job and average direct operating costs per total job increased as a result of this increase in the proportion of larger multi-stage fracturing jobs and the increased size of the jobs in 2014 as compared to 2013. Depreciation expense increased due to capital expenditures.

Oil and Natural Gas Production and Exploration |  | 2014 |  |  | 2013 |  |  | % Change |
|  | (Dollars in thousands) |  |  |  |  |
Revenues-Oil |  | $ | 34,377 |  |  | $ | 41,039 |  |  |  | (16.2 | )%
Revenues - Natural gas and liquids |  |  | 4,467 |  |  |  | 4,290 |  |  |  | 4.1 | %
Revenues-Total |  |  | 38,844 |  |  |  | 45,329 |  |  |  | (14.3 | )%
Direct operating costs |  |  | 9,421 |  |  |  | 9,738 |  |  |  | (3.3 | )%
Margin (1) |  |  | 29,423 |  |  |  | 35,591 |  |  |  | (17.3 | )%
Depletion and impairment |  |  | 20,086 |  |  |  | 18,402 |  |  |  | 9.2 | %
Operating income |  | $ | 9,337 |  |  | $ | 17,189 |  |  |  | (45.7 | )%
Capital expenditures |  | $ | 26,915 |  |  | $ | 22,925 |  |  |  | 17.4 | %

(1) | Margin is defined as revenues less direct operating costs and excludes depletion and impairment.

Oil revenues decreased primarily as a result of production declines on existing wells. Direct operating costs include a reduction in taxes due to lower production and lower exploration costs. This was largely offset by higher lease operating expenses. Depletion and impairment expense in 2014 includes approximately $4.1 million of oil and natural gas property impairments compared to approximately $2.6 million of oil and natural gas property impairments in 2013.

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Corporate and Other |  | 2014 |  |  | 2013 |  |  | % Change |
|  | (Dollars in thousands) |  |  |  |  |
Selling, general and administrative |  | $ | 38,849 |  |  | $ | 37,720 |  |  |  | 3.0 | %
Depreciation |  | $ | 3,402 |  |  | $ | 3,223 |  |  |  | 5.6 | %
Net (gain) loss on asset disposals |  | $ | (8,705 | ) |  | $ | (2,286 | ) |  |  | 280.8 | %
Interest income |  | $ | 618 |  |  | $ | 716 |  |  |  | (13.7 | )%
Interest expense |  | $ | 21,430 |  |  | $ | 21,210 |  |  |  | 1.0 | %
Other income (expense) |  | $ | 3 |  |  | $ | 780 |  |  |  | (99.6 | )%
Capital expenditures |  | $ | 2,164 |  |  | $ | 2,638 |  |  |  | (18.0 | )%

Selling, general and administrative expense increased in 2014 primarily as a result of increased personnel costs. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. In 2014, the net gain on asset disposals resulted primarily from miscellaneous sales of drilling equipment.

Adjusted EBITDA

Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by generally accepted accounting principles (“GAAP”). We define Adjusted EBITDA as net income plus net interest expense, income tax expense and depreciation, depletion, amortization and impairment expense. We present Adjusted EBITDA (a non-GAAP measure) because we believe it provides to both management and investors additional information with respect to both the performance of our fundamental business activities and our ability to meet our capital expenditures and working capital requirements. Adjusted EBITDA should not be construed as an alternative to the GAAP measures of net income or operating cash flow.

| Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
| 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Net income | $ | 15,976 |  |  | $ | 74,420 |  |  | $ | 105,081 |  |  | $ | 171,418 |
Income tax expense |  | 7,556 |  |  |  | 43,301 |  |  |  | 50,403 |  |  |  | 98,957 |
Net interest expense |  | 6,759 |  |  |  | 7,210 |  |  |  | 20,812 |  |  |  | 20,494 |
Depreciation, depletion, amortization and impairment |  | 237,825 |  |  |  | 140,734 |  |  |  | 538,573 |  |  |  | 414,351 |
Adjusted EBITDA | $ | 268,116 |  |  | $ | 265,665 |  |  | $ | 714,869 |  |  | $ | 705,220 |

Income Taxes

Our effective income tax rate was 32.4% for the nine months ended September 30, 2014, compared to 36.6% for the nine months ended September 30, 2013. The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008), and allows a deduction of 9% on the lesser of qualified production activities income or taxable income. The prior year Domestic Production Activities Deduction was smaller due to lower taxable income after the utilization of bonus depreciation and a federal net operating loss carryforward. In 2014, we do not have any remaining federal net operating loss carryforward, and bonus depreciation is currently unavailable, resulting in higher taxable income and, therefore, a larger Domestic Production Activities Deduction.

Recently Issued Accounting Standards

In May 2014, the FASB issued an accounting standards update to provide guidance on the recognition of revenue from customers. Under this guidance, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects in exchange for the goods or services. This guidance also requires more detailed disclosures to enable users of the financial statements to understand the nature, amount, timing and uncertainty, if any, of revenue and cash flows arising from contracts with customers. The requirements in this update are effective during interim and annual periods beginning after December 15, 2016. We are currently evaluating the impact this guidance will have on our consolidated financial statements.

In June 2014, the FASB issued an accounting standards update to provide guidance on the accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. The guidance requires that a performance target that affects vesting and that could be achieved after the requisite service period is treated as a performance condition. The requirements in this update are effective during interim and annual periods beginning after December 15, 2015. The adoption of this update is not expected to have a material impact on our consolidated financial statements.

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Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition

Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by factors such as market supply and demand, domestic and international military, political, economic and weather conditions, the ability of OPEC to set and maintain production and price targets, technical advances affecting energy consumption and production and the price and availability of alternative fuels. All of these factors are beyond our control. Declines in the market prices of natural gas and oil caused our customers to significantly reduce their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low throughout 2009. Drilling activities increased in 2010 as did the prices for oil and natural gas. The increased drilling activity was largely attributable to increased development of unconventional oil and natural gas reservoirs and an improvement in the price of oil. Drilling for oil and liquids rich targets continued to increase in 2011 as oil averaged $94.86 per barrel for the year (WTI spot price as reported by the United States Energy Information Administration). Natural gas prices decreased in 2011 to an average of $4.00 per Mcf (Henry Hub spot price as reported by the United States Energy Information Administration). This decrease continued into 2012 where natural gas prices fell below $2.00 per Mcf in April and averaged $2.75 per Mcf for the year, resulting in continued low levels of drilling activity for natural gas in 2012. The increase in drilling activity in oil rich basins absorbed some of the decrease in demand for natural gas drilling activities in 2012. During 2013, natural gas prices averaged $3.73 per Mcf, and oil prices averaged $97.91 per barrel, and demand for natural gas drilling activities continued to decline. During the nine months ended September 30, 2014, natural gas prices averaged $4.59 per Mcf and oil prices averaged $99.96 per barrel and demand for drilling activities increased. Construction of new land drilling rigs in the United States during the last decade has significantly contributed to excess capacity in total available drilling rigs. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for oil and natural gas would likely result in lower demand for our drilling rigs and pressure pumping services and could adversely affect our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our drilling rigs and pressure pumping services.

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

We currently have exposure to interest rate market risk associated with any borrowings that we have under our revolving credit facility and term loan facility. Interest is paid on the outstanding principal amount of borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.25% to 3.25% and the margin on base rate loans ranges from 1.25% to 2.25%, based on our debt to capitalization ratio. At September 30, 2014, the margin on LIBOR loans was 2.25% and the margin on base rate loans was 1.25%. As of September 30, 2014, we had no balances outstanding under our revolving credit facility and $85.0 million outstanding under our term loan facility at an interest rate of 2.50%. The interest rate on the borrowings outstanding under our revolving credit and term loan facilities is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate.

We conduct a portion of our business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars. This currency risk is not material to our results of operations or financial condition.

The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.

ITEM 4. Controls and Procedures

Disclosure Controls and Procedures — We maintain disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act), designed to ensure that the information required to be disclosed in the reports that we file with the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10‑Q. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of September 30, 2014.

Changes in Internal Control Over Financial Reporting —There were no changes in our internal control over financial reporting during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act.

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

In May 2013, the U.S. Equal Employment Opportunity Commission notified us of cause findings related to certain of our employment practices. The cause findings relate to allegations that we tolerated a hostile work environment for employees based on national origin and race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. We and the EEOC engaged in the statutory conciliation process. In March 2014, the EEOC notified us that this matter will be forwarded to its legal unit for litigation review. We believe that litigation will ensue. We intend to defend ourselves vigorously and, based on the information available to us at this time, we do not expect the outcome of this matter to have a material adverse effect on our financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter.

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ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended September 30, 2014.

|  |  |  |  |  |  |  |  |  |  |  |  |  | Approximate Dollar |
|  |  |  |  |  |  |  |  |  | Total Number of |  |  | Value of Shares |
|  |  |  |  |  |  |  |  |  | Shares (or Units) |  |  | That May Yet Be |
|  |  |  |  |  |  |  |  |  | Purchased as Part |  |  | Purchased Under the |
|  | Total |  |  | Average Price |  |  | of Publicly |  |  | Plans or |
|  | Number of Shares |  |  | Paid per |  |  | Announced Plans |  |  | Programs (in |
Period Covered |  | Purchased |  |  | Share |  |  | or Programs |  |  | thousands)(1) |
July 2014 |  |  | — |  |  |  | — |  |  | — |  |  | $ | 187,016 |
August 2014 |  | — |  |  | — |  |  | — |  |  | $ | 187,016 |
September 2014 |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 187,016 |
Total |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 187,016 |

(1) | On September 9, 2013, we announced that our Board of Directors approved a stock buyback program authorizing purchases of up to $200 million of our common stock in open market or privately negotiated transactions.

ITEM 6. Exhibits

The following exhibits are filed herewith or incorporated by reference, as indicated:

3.1 |  | Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3.2 |  | Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3.3 |  | Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated herein by reference).
10.1 |  | Indemnification Agreement entered into between Patterson-UTI Energy, Inc. and Tiffany J. Thom dated August 8, 2014. See Form of Indemnification Agreement entered into between Patterson-UTI Energy, Inc. and certain of its directors and officers, filed on April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference.
31.1* |  | Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
31.2* |  | Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
32.1* |  | Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101* |  | The following materials from Patterson-UTI Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Condensed Balance Sheets, (ii) the Consolidated Condensed Statements of Operations, (iii) the Consolidated Condensed Statements of Comprehensive Income, (iv) the Consolidated Condensed Statement of Changes in Stockholders’ Equity, (v) the Consolidated Condensed Statements of Cash Flows, and (vi) Notes to Consolidated Condensed Financial Statements.

* | filed herewith

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PATTERSON-UTI ENERGY, INC.
By: |  | /s/ John E. Vollmer III
|  | John E. Vollmer III
|  | Senior Vice President – Corporate Development,
|  | Chief Financial Officer and Treasurer
|  | (Principal Financial and Accounting Officer and Duly Authorized Officer)

Date: October 27, 2014

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