10-Q 1 pten-10q_20180331.htm 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2018

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.)
10713 W. SAM HOUSTON PKWY N, SUITE 800 HOUSTON, TEXAS |  | 77064
(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 ☑ 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 ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer |  | ☑ |  | Accelerated filer |  | ☐ |  | Smaller reporting company |  | ☐
Non-accelerated filer |  | ☐ |  |  |  |  |  | Emerging growth company |  | ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

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

221,807,221 shares of common stock, $0.01 par value, as of April 27, 2018

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

|  | PART I — FINANCIAL INFORMATION |  |
|  |  |  | Page
ITEM 1. |  | Financial Statements |  |
|  | Unaudited condensed consolidated balance sheets |  | 3
|  | Unaudited condensed consolidated statements of operations |  | 4
|  | Unaudited condensed consolidated statements of comprehensive loss |  | 5
|  | Unaudited condensed consolidated statement of changes in stockholders’ equity |  | 6
|  | Unaudited condensed consolidated statements of cash flows |  | 7
|  | Notes to unaudited condensed consolidated financial statements |  | 8
ITEM 2. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations |  | 28
ITEM 3. |  | Quantitative and Qualitative Disclosures About Market Risk |  | 38
ITEM 4. |  | Controls and Procedures |  | 39
|  | PART II — OTHER INFORMATION |  |
ITEM 1. |  | Legal Proceedings |  | 40
ITEM 2. |  | Unregistered Sales of Equity Securities and Use of Proceeds |  | 40
ITEM 6. |  | Exhibits |  | 41
Signature |  |  |  | 42

P ART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

The following unaudited condensed consolidated 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

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)

| March 31, |  |  | December 31, |
| 2018 |  |  | 2017 |
ASSETS |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |
Cash and cash equivalents | $ | 304,251 |  |  | $ | 42,828 |
Accounts receivable, net of allowance for doubtful accounts of $2,296 and $2,323 at March 31, 2018 and December 31, 2017, respectively |  | 596,888 |  |  |  | 580,354 |
Federal and state income taxes receivable |  | 1,128 |  |  |  | 1,152 |
Inventory |  | 72,069 |  |  |  | 69,167 |
Other |  | 64,639 |  |  |  | 53,354 |
Total current assets |  | 1,038,975 |  |  |  | 746,855 |
Property and equipment, net |  | 4,217,049 |  |  |  | 4,254,730 |
Goodwill and intangible assets |  | 689,398 |  |  |  | 687,072 |
Deposits on equipment purchases |  | 18,645 |  |  |  | 16,351 |
Deferred tax assets, net |  | 1,007 |  |  |  | 3,875 |
Other |  | 50,650 |  |  |  | 49,973 |
Total assets | $ | 6,015,724 |  |  | $ | 5,758,856 |
LIABILITIES AND STOCKHOLDERS' EQUITY |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |
Accounts payable | $ | 359,582 |  |  | $ | 319,621 |
Accrued expenses |  | 241,904 |  |  |  | 226,629 |
Total current liabilities |  | 601,486 |  |  |  | 546,250 |
Borrowings under revolving credit facility |  | — |  |  |  | 268,000 |
Long-term debt, net of debt discount and issuance costs of $6,164 and $1,217 at March 31, 2018 and December 31, 2017, respectively |  | 1,118,836 |  |  |  | 598,783 |
Deferred tax liabilities, net |  | 348,250 |  |  |  | 350,836 |
Other |  | 12,611 |  |  |  | 12,494 |
Total liabilities |  | 2,081,183 |  |  |  | 1,776,363 |
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 266,298,983 and 266,259,083 issued and 221,571,572 and 222,456,472 outstanding at March 31, 2018 and December 31, 2017, respectively |  | 2,663 |  |  |  | 2,662 |
Additional paid-in capital |  | 2,795,672 |  |  |  | 2,785,823 |
Retained earnings |  | 2,067,007 |  |  |  | 2,105,897 |
Accumulated other comprehensive income |  | 4,838 |  |  |  | 6,822 |
Treasury stock, at cost, 44,727,411 and 43,802,611 shares at March 31, 2018 and December 31, 2017, respectively |  | (935,639 | ) |  |  | (918,711 | )
Total stockholders' equity |  | 3,934,541 |  |  |  | 3,982,493 |
Total liabilities and stockholders' equity | $ | 6,015,724 |  |  | $ | 5,758,856 |

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

3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands, except per share data)

| Three Months Ended |
| March 31, |
| 2018 |  |  | 2017 |
Operating revenues: |  |  |  |  |  |  |
Contract drilling | $ | 327,803 |  |  | $ | 158,728 |
Pressure pumping |  | 406,784 |  |  |  | 141,174 |
Directional drilling |  | 48,616 |  |  |  | — |
Other |  | 25,961 |  |  |  | 5,273 |
Total operating revenues |  | 809,164 |  |  |  | 305,175 |
Operating costs and expenses: |  |  |  |  |  |  |
Contract drilling |  | 212,583 |  |  |  | 108,221 |
Pressure pumping |  | 320,970 |  |  |  | 119,013 |
Directional drilling |  | 37,689 |  |  |  | — |
Other |  | 17,745 |  |  |  | 3,259 |
Depreciation, depletion, amortization and impairment |  | 209,892 |  |  |  | 156,217 |
Selling, general and administrative |  | 32,817 |  |  |  | 18,852 |
Merger and integration expenses |  | 1,991 |  |  |  | 5,156 |
Other operating income, net |  | (2,421 | ) |  |  | (12,904 | )
Total operating costs and expenses |  | 831,266 |  |  |  | 397,814 |
Operating loss |  | (22,102 | ) |  |  | (92,639 | )
Other income (expense): |  |  |  |  |  |  |
Interest income |  | 1,423 |  |  |  | 406 |
Interest expense, net of amount capitalized |  | (13,625 | ) |  |  | (8,270 | )
Other |  | 169 |  |  |  | 17 |
Total other expense |  | (12,033 | ) |  |  | (7,847 | )
Loss before income taxes |  | (34,135 | ) |  |  | (100,486 | )
Income tax expense (benefit) |  | 282 |  |  |  | (36,947 | )
Net loss | $ | (34,417 | ) |  | $ | (63,539 | )
Net loss per common share: |  |  |  |  |  |  |
Basic | $ | (0.16 | ) |  | $ | (0.40 | )
Diluted | $ | (0.16 | ) |  | $ | (0.40 | )
Weighted average number of common shares outstanding: |  |  |  |  |  |  |
Basic |  | 220,783 |  |  |  | 160,062 |
Diluted |  | 220,783 |  |  |  | 160,062 |
Cash dividends per common share | $ | 0.02 |  |  | $ | 0.02 |

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

4

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited, in thousands)

| Three Months Ended |
| March 31, |
| 2018 |  |  | 2017 |
Net loss | $ | (34,417 | ) |  | $ | (63,539 | )
Other comprehensive income (loss), net of taxes of $0 for all periods: |  |  |  |  |  |  |
Foreign currency translation adjustment |  | (1,984 | ) |  |  | 1,049 |
Total comprehensive loss | $ | (36,401 | ) |  | $ | (62,490 | )

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

5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED 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 (Loss) |  |  | Stock |  |  | Total |
Balance, December 31, 2017 |  | 266,259 |  |  | $ | 2,662 |  |  | $ | 2,785,823 |  |  | $ | 2,105,897 |  |  | $ | 6,822 |  |  | $ | (918,711 | ) |  |  | 3,982,493 |
Net loss |  | — |  |  |  | — |  |  |  | — |  |  |  | (34,417 | ) |  |  | — |  |  |  | — |  |  |  | (34,417 | )
Foreign currency translation adjustment |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (1,984 | ) |  |  | — |  |  |  | (1,984 | )
Exercise of stock options |  | 40 |  |  |  | 1 |  |  |  | 484 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 485 |
Stock-based compensation |  | — |  |  |  | — |  |  |  | 9,365 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 9,365 |
Payment of cash dividends |  | — |  |  |  | — |  |  |  | — |  |  |  | (4,443 | ) |  |  | — |  |  |  | — |  |  |  | (4,443 | )
Dividend equivalents |  | — |  |  |  | — |  |  |  | — |  |  |  | (30 | ) |  |  | — |  |  |  | — |  |  |  | (30 | )
Purchase of treasury stock |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (16,928 | ) |  |  | (16,928 | )
Balance, March 31, 2018 |  | 266,299 |  |  | $ | 2,663 |  |  | $ | 2,795,672 |  |  | $ | 2,067,007 |  |  | $ | 4,838 |  |  | $ | (935,639 | ) |  | $ | 3,934,541 |

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

6

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

| Three Months Ended |
| March 31, |
| 2018 |  |  | 2017 |
Cash flows from operating activities: |  |  |  |  |  |  |
Net loss | $ | (34,417 | ) |  | $ | (63,539 | )
Adjustments to reconcile net loss to net cash provided by operating activities: |  |  |  |  |  |  |
Depreciation, depletion, amortization and impairment |  | 209,892 |  |  |  | 156,217 |
Dry holes and abandonments |  | 96 |  |  |  | — |
Deferred income tax expense (benefit) |  | 282 |  |  |  | (36,947 | )
Stock-based compensation expense |  | 9,365 |  |  |  | 7,131 |
Net gain on asset disposals |  | (10,410 | ) |  |  | (13,560 | )
Amortization of debt discount and issuance costs |  | 170 |  |  |  | 87 |
Changes in operating assets and liabilities: |  |  |  |  |  |  |
Accounts receivable |  | (16,468 | ) |  |  | (62,291 | )
Income taxes receivable |  | 19 |  |  |  | 248 |
Inventory and other assets |  | 2,709 |  |  |  | 9,931 |
Accounts payable |  | (22,514 | ) |  |  | 11,252 |
Accrued expenses |  | 11,174 |  |  |  | (3,233 | )
Other liabilities |  | 67 |  |  |  | 261 |
Net cash provided by operating activities |  | 149,965 |  |  |  | 5,557 |
Cash flows from investing activities: |  |  |  |  |  |  |
Acquisition |  | (3,800 | ) |  |  | — |
Purchases of property and equipment |  | (122,921 | ) |  |  | (68,440 | )
Proceeds from disposal of assets |  | 10,294 |  |  |  | 25,861 |
Net cash used in investing activities |  | (116,427 | ) |  |  | (42,579 | )
Cash flows from financing activities: |  |  |  |  |  |  |
Proceeds of equity offering |  | — |  |  |  | 471,570 |
Purchases of treasury stock |  | (16,928 | ) |  |  | — |
Proceeds from exercise of options |  | 485 |  |  |  | — |
Dividends paid |  | (4,443 | ) |  |  | (3,326 | )
Debt issuance costs |  | (4,198 | ) |  |  | — |
Proceeds from long-term debt |  | 521,194 |  |  |  | — |
Proceeds from borrowings under revolving credit facility |  | 79,000 |  |  |  | 10,000 |
Repayment of borrowings under revolving credit facility |  | (347,000 | ) |  |  | (10,000 | )
Net cash provided by financing activities |  | 228,110 |  |  |  | 468,244 |
Effect of foreign exchange rate changes on cash |  | (225 | ) |  |  | 234 |
Net increase in cash and cash equivalents |  | 261,423 |  |  |  | 431,456 |
Cash and cash equivalents at beginning of period |  | 42,828 |  |  |  | 35,152 |
Cash and cash equivalents at end of period | $ | 304,251 |  |  | $ | 466,608 |
Supplemental disclosure of cash flow information: |  |  |  |  |  |  |
Net cash (paid) received during the period for: |  |  |  |  |  |  |
Interest, net of capitalized interest of $340 in 2018 and $155 in 2017 | $ | (2,206 | ) |  | $ | (634 | )
Income taxes | $ | 21 |  |  | $ | 248 |
Non-cash investing and financing activities: |  |  |  |  |  |  |
Receivable from property and equipment insurance | $ | 15,000 |  |  | $ | — |
Net increase in payables for purchases of property and equipment | $ | 62,488 |  |  | $ | 21,297 |
Net increase in deposits on equipment purchases | $ | (2,294 | ) |  | $ | (3,056 | )

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

7

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation

Basis of presentation - The unaudited interim condensed consolidated 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 condensed consolidated financial statements have been prepared by management of the Company pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) 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 recurring adjustments considered necessary for a fair statement of the information in conformity with U.S. GAAP have been included. The unaudited condensed consolidated balance sheet as of December 31, 2017, as presented herein, was derived from the audited consolidated balance sheet of the Company, but does not include all disclosures required by U.S. GAAP. These unaudited condensed consolidated 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, 2017. The results of operations for the three months ended March 31, 2018 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 use 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.

On December 12, 2016, the Company entered into an Agreement and Plan of Merger (the “merger agreement”) with Seventy Seven Energy Inc. (“SSE”), and the merger closed on April 20, 2017 (the “merger date”). The Company’s results include the results of operations of SSE since the merger date (See Note 2). On October 11, 2017, the Company acquired all of the issued and outstanding limited liability company interests of MS Directional, LLC (f/k/a Multi-Shot, LLC) (“MS Directional”). The Company’s results include the results of operations of MS Directional since October 11, 2017 (See Note 2). The acquisition of MS Directional created a new directional drilling reporting segment for the Company (See Note 14).

Recently Issued Accounting Standards – In May 2014, the Financial Accounting Standards Board (“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, 2017. The Company adopted this new revenue guidance effective January 1, 2018, utilizing the modified retrospective method, and expanded its consolidated financial statement disclosures in order to comply with the update (See Note 3). The adoption of this update did not have a material impact on the Company’s consolidated financial statements.

In February 2016, the FASB issued an accounting standards update to provide guidance for the accounting for leasing transactions. The standard requires the lessee to recognize a lease liability along with a right-of-use asset for all leases with a term longer than one year. A lessee is permitted to make an accounting policy election by class of underlying asset to not recognize the lease liability and related right-of-use asset for leases with a term of one year or less. The provisions of this standard also apply to situations where the Company is the lessor and may require the Company to separately account for lease components from non-lease components within a contract. The requirements in this update are effective during interim and annual periods beginning after December 15, 2018. The Company is currently evaluating the impact that this new guidance will have on its consolidated financial statements.

In August 2016, the FASB issued an accounting standards update to clarify the presentation of cash receipts and payments in specific situations on the statement of cash flows. The requirements in this update are effective during interim and annual periods in fiscal years beginning after December 15, 2017. The adoption of this update on January 1, 2018 did not have a material impact on the Company’s consolidated financial statements.

8

In May 2017, the FASB issued an accounting standards update that provided clarity on which changes to the terms or conditions of share-based payment awards require an entity to apply modification accounting provisions. The requirements in this update are effective during interim and annual periods in fiscal years beginning after December 15, 2017. The adoption of this update on January 1, 2018 did not have a material impact on the Company’s consolidated fi nancial statements.

In March 2018, the FASB issued an accounting standards update to update the income tax accounting in U.S. GAAP to reflect the SEC interpretive guidance released on December 22, 2017, when significant U.S. tax law changes were enacted with the enactment of the Tax Cuts and Jobs Act (“Tax Reform”). The adoption of this update in March 2018 did not have a material impact on the Company’s consolidated financial statements, as the Company was already following the SEC guidance. See Note 12 for additional information.

2. Acquisitions

Seventy Seven Energy Inc. (“SSE”)

On April 20, 2017, pursuant to the merger agreement, a subsidiary of the Company was merged with and into SSE, with SSE continuing as the surviving entity and one of the Company’s wholly owned subsidiaries (the “SSE merger”). Pursuant to the terms of the merger agreement, the Company acquired all of the issued and outstanding shares of common stock of SSE, in exchange for approximately 46.3 million shares of common stock of the Company. Concurrent with the closing of the merger, the Company repaid all of the outstanding debt of SSE totaling $472 million. Based on the closing price of the Company’s common stock on April 20, 2017, the total fair value of the consideration transferred to effect the acquisition of SSE was approximately $1.5 billion. On April 20, 2017, following the SSE merger, SSE was merged with and into a newly-formed subsidiary of the Company named Seventy Seven Energy LLC (“SSE LLC”), with SSE LLC continuing as the surviving entity and one of the Company’s wholly owned subsidiaries.

Through the SSE merger, the Company acquired a fleet of 91 drilling rigs, 36 of which the Company considers to be APEX® rigs. Additionally, through the SSE merger, the Company acquired approximately 500,000 horsepower of modern, efficient fracturing equipment. The oilfield rentals business acquired through the SSE merger has a modern, well-maintained fleet of premium rental tools, and it provides specialized services for land-based oil and natural gas drilling, completion and workover activities.

The merger has been accounted for as a business combination using the acquisition method. Under the acquisition method of accounting, the fair value of the consideration transferred is allocated to the tangible and intangible assets acquired and the liabilities assumed based on their estimated fair values as of the acquisition date, with the remaining unallocated amount recorded as goodwill.

The total fair value of the consideration transferred was determined as follows (in thousands, except stock price):

Shares of Company common stock issued to SSE shareholders |  | 46,298 |
Company common stock price on April 20, 2017 | $ | 22.45 |
Fair value of common stock issued | $ | 1,039,396 |
Plus SSE long-term debt repaid by Company | $ | 472,000 |
Total fair value of consideration transferred | $ | 1,511,396 |

9

The final determination of the fair value of assets acquired and liabilities assumed at the merger date will be completed as soon as possible, but no later than one year from the merger date (the “measurement period”). The Company’s preliminary purchase price allocation is subject to revision as additional information about the fair value of assets and liabilities becomes available. Additional information that existed as of the merger date, but at the time was unknown to the Company, may become known to the Company during the remainder of the measurement period. The final determination of fair value may differ mat erially from these preliminary estimates. The following table represents the preliminary allocation of the total purchase price of SSE to the assets acquired and the liabilities assumed based on the fair value at the merger date, with the excess of the pu rchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (in thousands):

Identifiable assets acquired |  |  |
Cash and cash equivalents | $ | 37,806 |
Accounts receivable |  | 149,659 |
Inventory |  | 8,518 |
Other current assets |  | 19,038 |
Property and equipment |  | 984,433 |
Other long-term assets |  | 20,918 |
Intangible assets |  | 22,500 |
Total identifiable assets acquired |  | 1,242,872 |
Liabilities assumed |  |  |
Accounts payable and accrued liabilities |  | 133,415 |
Deferred income taxes |  | 32,881 |
Other long-term liabilities |  | 1,734 |
Total liabilities assumed |  | 168,030 |
Net identifiable assets acquired |  | 1,074,842 |
Goodwill |  | 436,554 |
Total net assets acquired | $ | 1,511,396 |

The goodwill reflected above has decreased $1.9 million from the original preliminary purchase price allocation as a result of measurement period adjustments, primarily related to a valuation adjustment to a long-term asset offset by valuation adjustments to accounts payable and accrued liabilities and deferred income taxes.

The acquired goodwill is not deductible for tax purposes. Among the factors that contributed to a purchase price resulting in the recognition of goodwill was SSE’s reputation as an experienced provider of high-quality contract drilling and pressure pumping services in a safe and efficient manner, access to new geographies, access to new product lines, increased scale of operations, supply chain and corporate efficiencies as well as infrastructure optimization. The acquired goodwill was attributable to three operating segments, with $309 million to contract drilling, $121 million to pressure pumping and $6.3 million to oilfield rentals.

A portion of the fair value consideration transferred has been provisionally assigned to identifiable intangible assets as follows:

| Fair Value |  |  | Weighted Average Useful Life |
| (in thousands) |  |  | (in years) |
Assets |  |  |  |  |  |  |
Favorable drilling contracts | $ | 22,500 |  |  |  | 0.83 |

MS Directional

On October 11, 2017, the Company acquired all of the issued and outstanding limited liability company interests of MS Directional. The aggregate consideration paid by the Company consisted of $69.8 million in cash and approximately 8.8 million shares of the Company’s common stock. The purchase price was subject to customary post-closing adjustments relating to cash, net working capital and indebtedness of MS Directional as of the closing. Based on the closing price of the Company’s common stock on the closing date of the transaction, the total fair value of the consideration transferred to effect the acquisition of MS Directional was approximately $257 million.

MS Directional is a leading directional drilling services company in the United States, with operations in most major producing onshore oil and gas basins. MS Directional provides a comprehensive suite of directional drilling services, including directional drilling, downhole performance motors, directional surveying, measurement while drilling, and wireline steering tools.

10

The acquisition has been accounted for as a business combination using the acquisition method. Under the acquisition method of accounting, the fair value of the consideration transferred is allocated to the tangible and intangible assets acquired an d the liabilities assumed based on their estimated fair values as of the acquisition date, with the remaining unallocated amount recorded as goodwill.

The total fair value of the consideration transferred was determined as follows (in thousands, except stock price):

Shares of Company common stock issued to MS Directional shareholders |  | 8,798 |
Company common stock price on October 11, 2017 | $ | 21.31 |
Fair value of common stock issued | $ | 187,494 |
Plus MS Directional long-term debt repaid by Company | $ | 63,000 |
Plus cash to sellers | $ | 6,781 |
Total fair value of consideration transferred | $ | 257,275 |

The final determination of the fair value of assets acquired and liabilities assumed at the acquisition date will be completed as soon as possible, but no later than one year from the acquisition date (the “measurement period”). The Company’s preliminary purchase price allocation is subject to revision as additional information about the fair value of assets and liabilities becomes available. Additional information that existed as of the acquisition date, but at the time was unknown to the Company, may become known to the Company during the remainder of the measurement period. The final determination of fair value may differ materially from these preliminary estimates. The following table represents the preliminary allocation of the total purchase price of MS Directional to the assets acquired and the liabilities assumed based on the fair value at the merger date, with the excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (in thousands):

Identifiable assets acquired |  |  |
Cash and cash equivalents | $ | 2,021 |
Accounts receivable |  | 42,782 |
Inventory |  | 28,060 |
Other current assets |  | 155 |
Property and equipment |  | 63,998 |
Other long-term assets |  | 318 |
Intangible assets |  | 74,682 |
Total identifiable assets acquired |  | 212,016 |
Liabilities assumed |  |  |
Accounts payable and accrued liabilities |  | 43,099 |
Other long-term liabilities |  | 327 |
Total liabilities assumed |  | 43,426 |
Net identifiable assets acquired |  | 168,590 |
Goodwill |  | 88,685 |
Total net assets acquired | $ | 257,275 |

The acquired goodwill is deductible for tax purposes. Among the factors that contributed to a purchase price resulting in the recognition of goodwill was MS Directional’s reputation as an experienced provider of high-quality directional drilling services in a safe and efficient manner, access to new product lines, favorable market trends underlying these new business lines, earnings and growth opportunities and future technology development possibilities. All of the goodwill acquired is attributable to the directional drilling operating segment.

A portion of the fair value consideration transferred has been provisionally assigned to identifiable intangible assets as follows:

| Fair Value |  |  | Weighted Average Useful Life |
| (in thousands) |  |  | (in years) |
Assets |  |  |  |  |  |  |
Developed technology | $ | 48,000 |  |  |  | 10.00 |
Customer relationships |  | 26,200 |  |  |  | 3.00 |
Internal use software |  | 482 |  |  |  | 5.00 |
| $ | 74,682 |  |  |  | 7.51 |

11

Pro Forma

The results of SSE’s operations since the SSE merger date of April 20, 2017 and the results of MS Directional since the acquisition date of October 11, 2017 are included in the Company’s condensed consolidated statement of operations. It is impractical to quantify the contribution of the SSE operations since the merger, as the contract drilling and pressure pumping businesses were fully integrated into the Company’s existing operations in 2017. The contribution of MS Directional for the three months ended March 31, 2018 accounts for substantially all of the Company’s directional drilling segment. The following pro forma condensed combined financial information was derived from the historical financial statements of the Company, SSE and MS Directional and gives effect to the acquisitions as if they had occurred on January 1, 2016. The below information reflects pro forma adjustments based on available information and certain assumptions the Company believes are reasonable, including (i) adjustments related to the depreciation and amortization of the fair value of acquired intangibles and fixed assets, (ii) removal of the historical interest expense of the acquired entities, (iii) the tax benefit of the aforementioned pro forma adjustments, and (iv) adjustments related to the common shares outstanding to reflect the impact of the consideration exchanged in the acquisitions. Additionally, the pro forma loss for the three months ended March 31, 2017 was adjusted to exclude the Company’s merger and integration-related costs of $5.2 million and SSE’s merger-related costs of $8.1 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the SSE merger or MS Directional acquisition. The pro forma results of operations also do not include any estimated costs that have been or will be incurred by the Company to integrate the SSE and MS Directional operations. The pro forma condensed combined financial information has been included for comparative purposes and are not necessarily indicative of the results that might have actually occurred had the SSE merger and MS Directional acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. The following table summarizes selected financial information of the Company on a pro forma basis (in thousands, except per share data):

| Three Months Ended |
| March 31, 2017 |
Revenues | $ | 530,787 |
Net loss |  | (69,944 | )
Loss per share |  | (0.32 | )

Superior QC, LLC (“Superior QC”)

During February 2018, the Company acquired the business of Superior QC, including its assets and intellectual property. Superior QC is a provider of software used to improve the accuracy of horizontal wellbore placement. Superior QC’s measurement while drilling (MWD) survey fault detection, isolation and recovery (FDIR) service is a new data analytics technology to analyze MWD survey data in real-time and more accurately identify the position of the well. The results of operations for the acquired Superior QC business are reported under the Company’s directional drilling business segment. This acquisition was not material to the Company’s consolidated financial statements.

3. Revenues

ASC Topic 606 Revenue from Contracts with Customers

On January 1, 2018, the Company adopted the new revenue guidance under Topic 606, Revenue from Contracts with Customers, using the modified retrospective method for contracts that were not complete at December 31, 2017. The adoption of the new accounting standard did not have a material impact on the Company’s consolidated financial statements and a cumulative adjustment was not recognized. Revenues for reporting periods beginning after January 1, 2018 are presented under Topic 606 while revenues prior to January 1, 2018 continue to be reported under previous revenue recognition requirements of Topic 605.

The Company’s contracts with customers include both long-term and short-term contracts. Services that primarily drive revenue earned for the Company include the operating business segments of contract drilling, pressure pumping and directional drilling that comprise the Company’s reportable segments. The Company also derives revenues from its other operations which include the Company’s operating business segments of oilfield rentals, oilfield technology, and oil and natural gas working interests. For more information on the Company’s business segments, see Note 14.

Charges for services are considered a series of distinct services. Since each distinct service in a series would be satisfied over time if it were accounted for separately, and the entity would measure its progress towards satisfaction using the same measure of progress for each distinct service in the series, the Company is able to account for these integrated services as a single performance obligation that is satisfied over time.

12

The transaction price is the amount of consideration to which the Company expects to be entitled in exchange for transferring promised goods or services to a customer, based on terms of the Company’s contracts with its customers. The consideration promised in a contract with a cu stomer may include fixed amounts and/or variable amounts. Payments received for services are considered variable consideration as the time in service will fluctuate as the services are provided. Topic 606 provides an allocation exception, which allows th e Company to allocate variable consideration to one or more distinct services promised in a series of distinct services that form part of a single performance obligation as long as certain criteria are met. These criteria state that the variable payment m ust relate specifically to the entity’s efforts to satisfy the performance obligation or transfer the distinct good or service, and allocation of the variable consideration is consistent with the standards’ allocation objective. Since payments received fo r services meet both of these criteria requirements, the Company recognizes revenue when the service is performed.

An estimate of variable consideration should be constrained to the extent that it is not probable that a significant revenue reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Payments received for other types of consideration are fully constrained as they are highly susceptible to factors outside the entity’s influence and therefore could be subject to a significant revenue reversal once resolved. As such, revenue received for these types of consideration is recognized when the service is performed. There are no unsatisfied performance obligations for which consideration is received.

Estimates of variable consideration are subject to change as facts and circumstances evolve. As such, the Company will evaluate its estimates of variable consideration that are subject to constraints throughout the contract period and revise estimates, if necessary, at the end of each reporting period.

The Company is a working interest owner of oil and natural gas properties located in Texas and New Mexico. The ownership terms are outlined in joint operating agreements for each well between the operator of the wells and the various interest owners, including the Company, who are considered non-operators of the well. The Company receives revenue each period for its working interest in the well during the period. The revenue received for the working interests from these oil and gas properties does not fall under the scope of the new revenue standard, and therefore, will continue to be reported under current guidance ASC 932-323 Extractive Activities – Oil and Gas, Investments – Equity Method and Joint Ventures.

Reimbursement Revenue – Reimbursements for the purchase of supplies, equipment, personnel services, shipping and other services that are provided at the request of the Company’s customers are recorded as revenue when incurred. The related costs are recorded as operating expenses when incurred.

The Company’s disaggregated revenue recognized from contracts with customers is included in Note 14.

Accounts Receivable and Contract Liabilities

Accounts receivable is the Company’s right to consideration once it becomes unconditional. Payment terms range from 30 to 60 days.

Accounts receivable balances were $593 million and $577 million as of March 31, 2018 and December 31, 2017, respectively. These balances do not include amounts related to the Company’s oil and gas working interests as those contracts are excluded from Topic 606. Accounts receivable balances are included in “Accounts Receivable” in the Condensed Consolidated Balance Sheets.

The Company does not have any contract asset balances, and as such, contract balances are not presented at the net amount at a contract level. Contract liabilities include prepayments received from customers prior to the requested services being completed. Once the services are complete and have been invoiced, the prepayment is applied against the customer’s account to offset the accounts receivable balance. Also included in contract liabilities are payments received from customers for the initial mobilization of newly constructed or upgraded rigs that were moved on location to the initial well site. These mobilization payments are allocated to the overall performance obligation and amortized over the initial term of the contract. During the three months ended March 31, 2018, approximately $405,000 was amortized and recorded in drilling revenue.

Contract liability balances for customer prepayments were $1.8 million and $9.1 million as of March 31, 2018 and December 31, 2017, respectively. Contract liability balances for deferred mobilization payments relating to newly constructed or upgraded rigs were $4.3 million and $4.7 million as of March 31, 2018 and December 31, 2017, respectively. Contract liability balances are included in “Accounts Payable” in the Condensed Consolidated Balance Sheets.

Contract Costs

Costs incurred for newly constructed or rig upgrades based on a contract with a customer are considered capital improvements and are capitalized to drilling equipment and depreciated over the estimated useful life of the asset.

13

Practical Expedients Adopt ed with Topic 606

The Company has elected to adopt the following practical expedients upon the transition date to Topic 606 on January 1, 2018:

| • | Use of portfolio approach: An entity can apply this guidance to a portfolio of contracts (or performance obligations) with similar characteristics if the entity reasonably expects that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts (or performance obligations) within that portfolio.

| • | Excluding disclosure about transaction price: As a practical expedient, an entity need not disclose the information for a performance obligation if either of the following conditions is met:

| a) | The performance obligation is part of a contract that has an original expected duration of one year or less.

| b) | The entity recognizes revenue from the satisfaction of the performance obligation.

| • | Excluding sales taxes from the transaction price: The scope of this policy election is the same as the scope of the policy election under previous guidance. This election provides exclusion from the measurement of the transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue producing transaction and collected by the entity from a customer.

| • | Significant financing component: An entity need not adjust the promised amount of consideration for the effects of a significant financing component if the entity expects, at contract inception, that the period between when the entity transfers a promised good or service to a customer and when the customer pays for that good or service will be one year or less.

| • | Completed contracts and treatment of contract modification: The FASB provided some relief from a full retrospective method in the form of four practical expedients and provided the option of a modified retrospective method with one practical expedient. Under that practical expedient, contracts modified prior to the beginning of the earliest reporting period presented under the new standard (e.g., January 1, 2016 for a public entity electing the full retrospective method), an entity can reflect the aggregate effect of all modifications that occur before the beginning of the earliest period presented under the new standard when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to the satisfied and unsatisfied performance obligations for the modified contract at transition.

| • | Costs of obtaining a contract: An entity can immediately expense costs of obtaining a contract if they would be amortized within a year.

4. Inventory

Inventory consisted of the following at March 31, 2018 and December 31, 2017 (in thousands):

| March 31, |  |  | December 31, |
| 2018 |  |  | 2017 |
Finished goods | $ | 2,269 |  |  | $ | 2,270 |
Work-in-process |  | 1,175 |  |  |  | 529 |
Raw materials and supplies |  | 68,625 |  |  |  | 66,368 |
Inventory | $ | 72,069 |  |  | $ | 69,167 |

14

5. Property and Equipment

Property and equipment consisted of the following at March 31, 2018 and December 31, 2017 (in thousands):

| March 31, |  |  | December 31, |
| 2018 |  |  | 2017 |
Equipment | $ | 8,155,843 |  |  | $ | 8,066,404 |
Oil and natural gas properties |  | 215,488 |  |  |  | 211,566 |
Buildings |  | 184,897 |  |  |  | 185,475 |
Land |  | 26,015 |  |  |  | 26,593 |
Total property and equipment |  | 8,582,243 |  |  |  | 8,490,038 |
Less accumulated depreciation, depletion and impairment |  | (4,365,194 | ) |  |  | (4,235,308 | )
Property and equipment, net | $ | 4,217,049 |  |  | $ | 4,254,730 |

On a periodic basis, the Company evaluates its fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional, vertical wells versus drilling longer, horizontal wells using higher specification rigs). The components comprising rigs that will no longer be marketed are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to the Company’s yards to be used as spare equipment. The remaining components of these rigs are retired.

In addition, the Company evaluates the recoverability of its long-lived assets whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable (a “triggering event”). Based on recent commodity prices, the Company’s results of operations for the three-month period ended March 31, 2018 and management’s expectations of operating results in future periods, the Company concluded that no triggering event occurred during the three months ended March 31, 2018 with respect to its contract drilling segment, its pressure pumping segment, its directional drilling segment or its other operations, except for oil and natural gas properties, which are discussed in the following paragraph. Management’s expectations of future operating results were based on the assumption that activity levels in all segments and its other operations will remain relatively stable or improve in response to relatively stable or increasing oil prices.

The Company reviews its proved oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field, and undiscounted cash flow estimates are prepared based on the Company’s expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between net book value and fair value. Impairment expense related to proved and unproved oil and natural gas properties totaled approximately $2,000 in the three months ended March 31, 2018 and $503,000 in the three months ended March 31, 2017 and is included in depreciation, depletion, amortization and impairment in the condensed consolidated statements of operations.

6. Goodwill and Intangible Assets

Goodwill — Goodwill by operating segment as of March 31, 2018 and changes for the three months then ended are as follows (in thousands):

| Contract |  |  | Pressure |  |  | Directional |  |  | Oilfield |  |  |  |  |
| Drilling |  |  | Pumping |  |  | Drilling |  |  | Rentals |  |  | Total |
Balance at beginning of period | $ | 395,060 |  |  |  | 121,444 |  |  | $ | 88,685 |  |  |  | 6,284 |  |  | $ | 611,473 |
Goodwill acquired |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Balance at end of period | $ | 395,060 |  |  | $ | 121,444 |  |  | $ | 88,685 |  |  | $ | 6,284 |  |  | $ | 611,473 |

There were no accumulated impairment losses related to goodwill as of March 31, 2018 or December 31, 2017.

15

Goodwill is evaluated at least annually as of December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For impairment testing purposes, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing are its operating segments. The Company determines whether it is more likely than not that the fair value of a reporting unit is less than i ts carrying value after considering qualitative, market and oth er factors, and if this is the case, any necessary goodwill impairment is determined using a quantitative impairment test. From time to time, the Company may perform quantitative testing for g oodwill impairment in lieu of performing the qualitative assessment. If th e resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized for the amount of the shortfall.

Intangible Assets — The following table presents the gross carrying amount and accumulated amortization of the intangible assets as of March 31, 2018 and December 31, 2017 (in thousands):

| March 31, 2018 |  |  | December 31, 2017 |
| Gross |  |  |  |  |  |  | Net |  |  | Gross |  |  |  |  |  |  | Net |
| Carrying |  |  | Accumulated |  |  | Carrying |  |  | Carrying |  |  | Accumulated |  |  | Carrying |
| Amount |  |  | Amortization |  |  | Amount |  |  | Amount |  |  | Amortization |  |  | Amount |
Customer relationships | $ | 26,200 |  |  | $ | (4,126 | ) |  |  | 22,074 |  |  | $ | 26,200 |  |  | $ | (1,943 | ) |  | $ | 24,257 |
Developed technology |  | 55,772 |  |  |  | (2,274 | ) |  |  | 53,498 |  |  |  | 48,000 |  |  |  | (1,137 | ) |  |  | 46,863 |
Favorable drilling contracts |  | 22,500 |  |  |  | (20,583 | ) |  |  | 1,917 |  |  |  | 22,500 |  |  |  | (18,482 | ) |  |  | 4,018 |
Internal use software |  | 482 |  |  |  | (46 | ) |  |  | 436 |  |  |  | 482 |  |  |  | (21 | ) |  |  | 461 |
| $ | 104,954 |  |  | $ | (27,029 | ) |  | $ | 77,925 |  |  | $ | 97,182 |  |  | $ | (21,583 | ) |  | $ | 75,599 |

Amortization expense on intangible assets of approximately $5.4 million and $911,000 was recorded in the three months ended March 31, 2018 and 2017, respectively.

7. Accrued Expenses

Accrued expenses consisted of the following at March 31, 2018 and December 31, 2017 (in thousands):

| March 31, |  |  | December 31, |
| 2018 |  |  | 2017 |
Salaries, wages, payroll taxes and benefits | $ | 55,079 |  |  | $ | 50,443 |
Workers' compensation liability |  | 81,266 |  |  |  | 80,751 |
Property, sales, use and other taxes |  | 24,825 |  |  |  | 29,332 |
Insurance, other than workers' compensation |  | 14,170 |  |  |  | 10,816 |
Accrued interest payable |  | 18,579 |  |  |  | 7,558 |
Accrued merger and integration |  | 8,685 |  |  |  | 16,101 |
Other |  | 39,300 |  |  |  | 31,628 |
Total | $ | 241,904 |  |  | $ | 226,629 |

8. Long Term Debt

2018 Credit Agreement — On March 27, 2018, the Company entered into an amended and restated credit agreement (the “Credit Agreement”) among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender, each of the other lenders and letter of credit issuers party thereto, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Syndication Agents, Royal Bank of Canada, as Documentation Agent and Wells Fargo Securities, LLC, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Lead Arrangers and Joint Book Runners.

The Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million. Subject to customary conditions, the Company may request that the lenders’ aggregate commitments be increased by up to $300 million, not to exceed total commitments of $900 million. The maturity date under the Credit Agreement is March 27, 2023. The Company has the option, subject to certain conditions, to exercise two one-year extensions of the maturity date.

16

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 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based upon the Company’s credit rating. 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 varies from 0.100% to 0.300% based on the Company’s credit rating.

No subsidiaries of the Company are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt in excess of the Priority Debt Basket (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.

The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that the Company believes are customary for agreements of this nature, including certain restrictions on the ability of the Company and each subsidiary of the Company to incur debt and grant liens. If the Company’s credit rating is below investment grade, the Company will become subject to a restricted payment covenant, which would require the Company to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. The Credit Agreement also requires that the Company’s total debt to capitalization ratio, expressed as a percentage, not exceed 50%. 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 end of the most recently ended fiscal quarter.

As of March 31, 2018, the Company had no amounts outstanding under the revolving credit facility. The Company had $81,000 in letters of credit outstanding under the revolving credit facility at March 31, 2018 and, as a result, had available borrowing capacity of approximately $600 million at that date.

2015 Reimbursement Agreement — On March 16, 2015, the Company entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which the Company may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of March 31, 2018, the Company had $54.9 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, the Company will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by the Company at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. The Company is obligated to pay to Scotiabank interest on all amounts not paid by the Company on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts.

The Company has also agreed that if obligations under the Credit Agreement are secured by liens on any of its or any of its subsidiaries’ property, then the Company’s reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015, the Company’s payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by subsidiaries of the Company that from time to time guarantee payment under the Credit Agreement. No subsidiaries of the Company currently guarantee payment under the Credit Agreement.

Series A & B 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 pays 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 pays 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.

17

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 b y each of the existing domestic subsidiaries of the Company ot her than subsidiaries that are not required to be guarantors under the Credit Agreement. No subsidiaries of the Company are currently required to be a guarantor under the Credit Agreement.

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 its 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. The Company was in compliance with these covenants at March 31, 2018.

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.

2028 Senior Notes – On January 19, 2018, the Company completed its offering of $525 million aggregate principal amount of the Company’s 3.95% Senior Notes due 2028 (the “2028 Notes”) initially guaranteed on a senior unsecured basis by certain of its subsidiaries. These guarantees were automatically released in connection with the Company’s entry into the Credit Agreement on March 27, 2018. The net proceeds before offering expenses were approximately $521 million of which the Company used $239 million to repay amounts outstanding under its revolving credit facility. The Company intends to use the remainder of the net proceeds for general corporate purposes.

The Company pays interest on the 2028 Notes on February 1 and August 1 of each year. The 2028 Notes will mature on February 1, 2028. The 2028 Notes bear interest at a rate of 3.95% per annum.

The 2028 Notes are senior unsecured obligations of the Company, which rank equally with all of the Company’s other existing and future senior unsecured debt and will rank senior in right of payment to all of the Company’s other future subordinated debt. The 2028 Notes will be effectively subordinated to any of the Company’s future secured debt to the extent of the value of the assets securing such debt. In addition, the 2028 Notes will be structurally subordinated to the liabilities (including trade payables) of the Company’s subsidiaries that do not guarantee the 2028 Notes. No subsidiaries of the Company are currently required to be a guarantor under the 2028 Notes. If subsidiaries of the Company guarantee the 2028 Notes in the future, such guarantees (the “Guarantees”) will rank equally in right of payment with all of the guarantors’ future unsecured senior debt and senior in right of payment to all of the guarantors’ future subordinated debt. The Guarantees will be effectively subordinated to any of the guarantors’ future secured debt to the extent of the value of the assets securing such debt.

The Company, at its option, may redeem the Notes in whole or part, at any time or from time to time at a redemption price equal to 100% of the principal amount of such 2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date, plus a make-whole premium. Additionally, commencing on November 1, 2027, the Company, at its option, may redeem the 2028 Notes in whole or part, at a redemption price equal to 100% of the principal amount of the 2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date.

The indenture pursuant to which the 2028 Notes were issued includes covenants that, among other things, limit the Company and its subsidiaries’ ability to incur certain liens, engage in sale and lease-back transactions or consolidate, merge, or transfer all or substantially all of their assets. These covenants are subject to important qualifications and limitations set forth in the indenture.

18

Upon the occurrence of a change of control, as defined in the indenture, each holder of the 2 028 Notes may require the Company to purchase all or a portion of such holder’s 2028 Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.

The indenture also provides for events of default which, if any of them occurs, would permit or require the principal of, premium, if any, and accrued interest, if any, on the 2028 Notes to become or to be declared due and payable.

Debt issuance costs – 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 $938,000 and $626,000 for the three months ended March 31, 2018 and 2017, respectively. Amortization of debt issuance costs for the three months ended March 31, 2018 includes $317,000 of debt issuance costs related to lenders of the Company’s previous credit agreement who did not participate in the 2018 Credit Agreement.

Presented below is a schedule of the principal repayment requirements of long-term debt as of March 31, 2018 (in thousands):

Year ending December 31, |  |  |
2018 | $ | — |
2019 |  | — |
2020 |  | 300,000 |
2021 |  | — |
2022 |  | 300,000 |
Thereafter |  | 525,000 |
Total | $ | 1,125,000 |

9. Commitments and Contingencies

As of March 31, 2018, the Company maintained letters of credit in the aggregate amount of $55.0 million primarily 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 March 31, 2018, no amounts had been drawn under the letters of credit.

As of March 31, 2018, the Company had commitments to purchase major equipment and make investments totaling approximately $183 million for its drilling, pressure pumping, directional drilling and oilfield rentals 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 2018, 2021 and 2041. As of March 31, 2018, the remaining obligation under these agreements was approximately $130 million, of which approximately $24.8 million relates to purchases required during the remainder of 2018. In the event the required minimum quantities are not purchased during certain periods, the Company could be required to make a liquidated damages payment to the respective vendor for any shortfall.

On January 22, 2018, an accident at a drilling site in Pittsburg County, Oklahoma resulted in the losses of life of five people, including three of the Company’s employees. Lawsuits have been filed in the District Court for Pittsburg County, Oklahoma in connection with the five individuals who lost their lives in the accident. These lawsuits allege various causes of action against the Company including negligence, gross negligence, knowledge that injury or death was substantially certain, acting with purpose, recklessness, wrongful death and survival, and the plaintiffs seek an unspecified amount of damages, including punitive or exemplary damages, costs, interest, and other relief. The Company disputes the plaintiffs’ allegations and intends to defend itself vigorously. Based on the information the Company has available as of the date of this Report, the Company believes that it has adequate insurance to cover any losses, excluding the applicable insurance deductibles and investigation-related expenses. However, if this accident is not fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on the Company’s business, financial condition, cash flows and results of operations.

The Company is party to various other 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.

19

10. Stockholders’ Equity

Cash Dividends — The Company paid cash dividends during the three months ended March 31, 2018 and 2017 as follows:

2018: | Per Share |  |  | Total |
|  |  |  |  | (in thousands) |
Paid on March 22, 2018 | $ | 0.02 |  |  | $ | 4,443 |

2017: | Per Share |  |  | Total |
|  |  |  |  | (in thousands) |
Paid on March 22, 2017 | $ | 0.02 |  |  | $ | 3,326 |

On April 25, 2018, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.04 per share to be paid on June 21, 2018 to holders of record as of June 7, 2018. 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 debt agreements 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. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of March 31, 2018, the Company had remaining authorization to purchase approximately $170 million of the Company’s outstanding common stock under the stock buyback program. Shares purchased under the buyback program are accounted for as treasury stock.

Treasury stock acquisitions during the three months ended March 31, 2018 were as follows (dollars in thousands):

| Shares |  |  | Cost |
Treasury shares at beginning of period |  | 43,802,611 |  |  | $ | 918,711 |
Purchases pursuant to stock buyback program |  | 924,800 |  |  |  | 16,928 |
Treasury shares at end of period |  | 44,727,411 |  |  | $ | 935,639 |

11. 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 include equity instruments in the form of stock options, restricted stock or restricted stock units that have included service conditions and, in certain cases, performance conditions. The Company’s share-based awards also include share-settled performance unit 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.

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 such 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. No options were granted in the three months ended March 31, 2018 or 2017.

Stock option activity from January 1, 2018 to March 31, 2018 follows:

|  |  |  |  | Weighted |
|  |  |  |  | Average |
| Underlying |  |  | Exercise Price |
| Shares |  |  | Per Share |
Outstanding at January 1, 2018 |  | 6,037,150 |  |  | $ | 20.35 |
Exercised |  | (40,000 | ) |  | $ | 12.12 |
Outstanding at March 31, 2018 |  | 5,997,150 |  |  | $ | 20.41 |
Exercisable at March 31, 2018 |  | 5,610,625 |  |  | $ | 20.52 |

20

Restricted Stock — For all restricted stock awards made 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-forfe itable 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, 2018 to March 31, 2018 follows:

|  |  |  |  | Weighted |
|  |  |  |  | Average Grant |
|  |  |  |  | Date Fair Value |
| Shares |  |  | Per Share |
Non-vested restricted stock outstanding at January 1, 2018 |  | 1,530,338 |  |  | $ | 21.41 |
Vested |  | (72,087 | ) |  | $ | 22.79 |
Forfeited |  | (100 | ) |  | $ | 20.85 |
Non-vested restricted stock outstanding at March 31, 2018 |  | 1,458,151 |  |  | $ | 21.34 |

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 and, in certain cases, performance conditions. Forfeitable dividend equivalents are accrued on certain restricted stock units and will be paid upon vesting. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period.

Restricted stock unit activity from January 1, 2018 to March 31, 2018 follows:

|  |  |  |  | Weighted |
|  |  |  |  | Average Grant |
|  |  |  |  | Date Fair Value |
| Shares |  |  | Per Share |
Non-vested restricted stock units outstanding at January 1, 2018 |  | 1,337,273 |  |  | $ | 19.80 |
Granted |  | 397,340 |  |  | $ | 18.44 |
Forfeited |  | (7,050 | ) |  | $ | 20.01 |
Non-vested restricted stock units outstanding at March 31, 2018 |  | 1,727,563 |  |  | $ | 19.49 |

Performance Unit Awards. The Company has granted share-settled performance unit awards to certain executive officers (the “Performance Units”) on an annual basis since 2010. The Performance Units provide for the recipients to receive a grant of shares of common stock upon the achievement of certain performance goals during a specified period established by the Compensation Committee. The performance period for the Performance Units is the three-year period commencing on April 1 of the year of grant, except that for the Performance Units granted in 2013 the performance period was extended pursuant to its terms, as described below, and for the Performance Units granted in 2017 the three-year performance period commenced on May 1.

The performance goals for the 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 respective Performance Units. Generally, the recipients will receive a target number of shares if the Company’s total shareholder return during the performance period, when compared to the peer group, is at the 50th percentile. If the Company’s total shareholder return during the performance period, when compared to the peer group, is at the 75th percentile or higher, then the recipients will receive two times the target number of shares. If the Company’s total shareholder return during the performance period, when compared to the peer group, is at the 25th percentile, then the recipients will only receive one-half of the target number of shares. If the Company’s total shareholder return during the performance period, when compared to the peer group, is between the 25th and 75th percentile, then the shares to be received by the recipients will be determined using linear interpolation for levels of achievement between these points.

For the Performance Units awarded prior to 2016, there is no payout unless the Company’s total shareholder return is positive and, when compared to the peer group, is at or above the 25th percentile. In respect of the 2013 Performance Units, for which the performance period ended March 31, 2016, the Company’s total shareholder return for the performance period was negative, the Company’s total shareholder return for the performance period when compared to the peer group was above the 75th percentile, and there was no payout; provided, however, that pursuant to the terms of those 2013 awards, if, during the two-year period ending March 31, 2018, the Company’s total shareholder return for any 30 consecutive day period equals or exceeds 18 percent on an annualized basis from April 1, 2013 through the last day of such 30 consecutive day period, and the recipient is actively employed by the Company through the last day of the extended performance period, then the Company will issue to the recipient the number of shares equal to the amount the recipient would have been entitled to receive had the Company’s total shareholder return been positive during the initial three-year performance period. The performance criteria for this extended period was not met and therefore there was no payout under the 2013 awards.

21

For the Performance Units granted in April 2016, if the Company’s total shareholder return is negative, and, when compared to the peer group is at or above the 25th percentile, then the recipients will receive one-half of the number of shares they would have received had the Company’s total shareholder return been positive. For the Performance Units granted in May 2017, the payout is based on relative perfor mance and do es not have an absolute performance requirement.

The total target number of shares with respect to the Performance Units for the awards granted in 2013-2017 is set forth below:

| 2017 |  |  | 2016 |  |  | 2015 |  |  | 2014 |  |  | 2013 |
| Performance |  |  | Performance |  |  | Performance |  |  | Performance |  |  | Performance |
| Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |
Target number of shares |  | 186,198 |  |  |  | 185,000 |  |  |  | 190,600 |  |  |  | 154,000 |  |  |  | 236,500 |

Because the performance units are share-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 Performance Units is set forth below (in thousands):

| 2017 |  |  | 2016 |  |  | 2015 |  |  | 2014 |  |  | 2013 |
| Performance |  |  | Performance |  |  | Performance |  |  | Performance |  |  | Performance |
| Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |
Fair value at date of grant | $ | 5,780 |  |  | $ | 3,854 |  |  | $ | 4,052 |  |  | $ | 5,388 |  |  | $ | 5,564 |

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

| 2017 |  |  | 2016 |  |  | 2015 |  |  | 2014 |  |  | 2013
| Performance |  |  | Performance |  |  | Performance |  |  | Performance |  |  | Performance
| Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards |  |  | Unit Awards
Three months ended March 31, 2018 | $ | 482 |  |  | $ | 321 |  |  | $ | 338 |  |  | NA |  |  | NA
Three months ended March 31, 2017 | NA |  |  | $ | 321 |  |  | $ | 338 |  |  | $ | 449 |  |  | NA

12. Income Taxes

The Company’s effective income tax rate fluctuates based on, among other factors, changes in statutory tax rates, changes in pretax income and nondeductible items, and changes in valuation allowances.

The Company’s effective income tax rate for the three months ended March 31, 2018 was (0.8)%, compared with 36.8% for the three months ended March 31, 2017. The lower effective income tax rate for the three months ended March 31, 2018 was primarily attributable to the impact of the reduction to the U.S. federal statutory tax rate and additional limitations for the deductibility of meals and entertainment expenses as a result of Tax Reform. The Company also recorded a valuation allowance against the net deferred tax assets of a certain Canadian subsidiary of the Company due to a change in judgment as to the realizability of these assets.

The Company recognized the income tax effects of Tax Reform in its audited financial statements included in the Company’s 2017 Annual Report on Form 10-K in accordance with Staff Accounting Bulletin No. 118, which provides SEC staff guidance for the application of ASC Topic 740, Income Taxes, in the reporting period during which Tax Reform was signed into law. The guidance also provides for a measurement period of up to one year from the enactment date of Tax Reform for the Company to complete its accounting for the U.S. tax law changes. As such, the Company’s 2017 financial results reflected the provisional estimate of the income tax effects of the Tax Reform. No subsequent adjustments have been made to the amounts recorded as of December 31, 2017, which continue to represent a provisional estimate of the impact of Tax Reform. The estimate of the impact of Tax Reform was based on certain assumptions and the Company’s current interpretation of Tax Reform. This estimate may change as the Company receives additional clarification and implementation guidance and as additional interpretations of Tax Reform become available.

13. Earnings Per Share

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

22

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, performance units and restricted stock units. The dilutive effect of stock options, performance units and restricted stock units is determined using the treasury stock method. The dilutive e ffect 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 c ommon shares other than non-vested shares of restricted stock.

The following table presents information necessary to calculate net loss per share for the three months ended March 31, 2018 and 2017 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 |
| March 31, |
| 2018 |  |  | 2017 |
BASIC EPS: |  |  |  |  |  |  |
Net loss attributed to common stockholders | $ | (34,417 | ) |  | $ | (63,539 | )
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock |  | 220,783 |  |  |  | 160,062 |
Basic net loss per common share | $ | (0.16 | ) |  | $ | (0.40 | )
DILUTED EPS: |  |  |  |  |  |  |
Net loss attributed to common stockholders | $ | (34,417 | ) |  | $ | (63,539 | )
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock |  | 220,783 |  |  |  | 160,062 |
Add dilutive effect of potential common shares |  | — |  |  |  | — |
Weighted average number of diluted common shares outstanding |  | 220,783 |  |  |  | 160,062 |
Diluted net loss per common share | $ | (0.16 | ) |  | $ | (0.40 | )
Potentially dilutive securities excluded as anti-dilutive |  | 9,738 |  |  |  | 9,017 |

14. Business Segments

At March 31, 2018, the Company had three business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) directional drilling services. Each of these segments represents a distinct type of business and has a separate management team that reports 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.

23

The following tables summ arize selected financial information relating to the Company’s business segments (in thousands):

| Three Months Ended |
| March 31, |
| 2018 |  |  | 2017 |
Revenues: |  |  |  |  |  |  |
Contract drilling | $ | 328,153 |  |  | $ | 159,055 |
Pressure pumping |  | 406,784 |  |  |  | 141,174 |
Directional drilling |  | 48,616 |  |  |  | — |
Other operations (a) |  | 29,653 |  |  |  | 5,618 |
Elimination of intercompany revenues (b) |  | (4,042 | ) |  |  | (672 | )
Total revenues | $ | 809,164 |  |  | $ | 305,175 |
Income (loss) before income taxes: |  |  |  |  |  |  |
Contract drilling | $ | (17,103 | ) |  | $ | (61,706 | )
Pressure pumping |  | 25,389 |  |  |  | (22,891 | )
Directional drilling |  | (4,913 | ) |  |  | — |
Other operations |  | (4,089 | ) |  |  | (1,951 | )
Corporate |  | (23,807 | ) |  |  | (18,995 | )
Other operating income, net (c) |  | 2,421 |  |  |  | 12,904 |
Interest income |  | 1,423 |  |  |  | 406 |
Interest expense |  | (13,625 | ) |  |  | (8,270 | )
Other |  | 169 |  |  |  | 17 |
Loss before income taxes | $ | (34,135 | ) |  | $ | (100,486 | )
Depreciation, depletion, amortization and impairment |  |  |  |  |  |  |
Contract drilling | $ | 130,917 |  |  | $ | 110,559 |
Pressure pumping |  | 56,522 |  |  |  | 42,250 |
Directional drilling |  | 10,902 |  |  |  | — |
Other operations |  | 9,314 |  |  |  | 2,172 |
Corporate |  | 2,237 |  |  |  | 1,236 |
Total depreciation, depletion, amortization and impairment | $ | 209,892 |  |  | $ | 156,217 |
Capital expenditures |  |  |  |  |  |  |
Contract drilling | $ | 75,247 |  |  | $ | 44,221 |
Pressure pumping |  | 24,923 |  |  |  | 19,413 |
Directional drilling |  | 12,829 |  |  |  | — |
Other operations |  | 9,396 |  |  |  | 4,352 |
Corporate |  | 526 |  |  |  | 454 |
Total capital expenditures | $ | 122,921 |  |  | $ | 68,440 |

| March 31, |  |  | December 31, |
| 2018 |  |  | 2017 |
Identifiable assets: |  |  |  |  |  |  |
Contract drilling | $ | 3,905,159 |  |  | $ | 3,931,994 |
Pressure pumping |  | 1,211,349 |  |  |  | 1,209,424 |
Directional drilling |  | 311,054 |  |  |  | 301,275 |
Other operations |  | 176,816 |  |  |  | 172,094 |
Corporate (d) |  | 411,346 |  |  |  | 144,069 |
Total assets | $ | 6,015,724 |  |  | $ | 5,758,856 |

(a) | Other operations includes the Company’s oilfield rentals business, pipe handling components and related technology business, oil and natural gas working interests and Middle East/North Africa activities.

(b) | Intercompany revenues consists of contract drilling intercompany revenues for services provided to other operations and also includes revenues from other operations for services provided to contract drilling, pressure pumping and within other operations.

(c) | Other operating income includes net gains associated with the disposal of assets related to corporate strategy decisions of the executive management group. Accordingly, the related gains have been excluded from the operating results of specific segments. This caption also includes expenses related to certain legal settlements net of insurance reimbursements.

(d) | Corporate assets primarily include cash on hand and certain property and equipment.

24

15. 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 as of March 31, 2018 and December 31, 2017 is set forth below (in thousands):

| March 31, 2018 |  |  | December 31, 2017 |
| Carrying |  |  | Fair |  |  | Carrying |  |  | Fair |
| Value |  |  | Value |  |  | Value |  |  | Value |
Revolving credit facility | $ | — |  |  | $ | — |  |  | $ | 268,000 |  |  | $ | 268,000 |
3.95% Senior Notes |  | 525,000 |  |  |  | 502,989 |  |  |  | — |  |  |  | — |
4.97% Series A Senior Notes |  | 300,000 |  |  |  | 306,304 |  |  |  | 300,000 |  |  |  | 303,966 |
4.27% Series B Senior Notes |  | 300,000 |  |  |  | 300,334 |  |  |  | 300,000 |  |  |  | 295,616 |
Total debt | $ | 1,125,000 |  |  | $ | 1,109,627 |  |  | $ | 868,000 |  |  | $ | 867,582 |

The carrying value of the balances outstanding under the revolving credit facility approximated its fair value as this instrument has floating interest rates. The fair value of the 3.95% Senior Notes at March 31, 2018 is based on discounted cash flows associated with the notes using the market rate of interest at March 31, 2018 of 4.49%. The fair values of the Series A Notes and Series B Notes at March 31, 2018 and December 31, 2017 are based on discounted cash flows associated with the respective notes using current market rates of interest at those respective dates. For the Series A Notes, the current market rates used in measuring this fair value were 4.08% at March 31, 2018 and 4.46% at December 31, 2017. For the Series B Notes, the current market rates used in measuring this fair value were 4.24% at March 31, 2018 and 4.64% at December 31, 2017. 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.

25

S PECIAL NOTE 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”), 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; rig counts; source and sufficiency of funds required for building new equipment, upgrading existing equipment and additional acquisitions (if opportunities arise); impact of inflation; demand for our services; competition; equipment availability; government regulation; debt service obligations; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts and often use words such as “anticipate,” “believe,” “budgeted,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “potential,” “project,” “pursue,” “should,” “strategy,” “target,” or “will,” 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. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These risks and uncertainties include, among others, risks and uncertainties relating to:

| • | availability of capital and the ability to repay indebtedness when due;

| • | 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;

| • | loss of key customers;

| • | utilization, margins and planned capital expenditures;

| • | synergies, costs and financial and operating impacts of acquisitions;

| • | interest rate volatility;

| • | compliance with covenants under our debt agreements;

| • | excess availability of land drilling rigs, pressure pumping and directional drilling equipment, including as a result of reactivation, improvement or construction;

| • | specialization of methods, equipment and services and new technologies;

| • | operating hazards attendant to the oil and natural gas business;

| • | failure by customers to pay or satisfy their contractual obligations (particularly with respect to fixed-term contracts);

| • | difficulty in building and deploying new equipment;

| • | expansion and development trends of the oil and natural gas industry;

| • | weather;

| • | shortages, delays in delivery, and interruptions in supply, of equipment and materials;

| • | the ability to retain management and field personnel;

| • | the ability to effectively identify and enter new markets;

| • | the ability to realize backlog;

| • | strength and financial resources of competitors;

| • | environmental risks and ability to satisfy future environmental costs;

| • | global economic conditions;

| • | adverse oil and natural gas industry conditions;

| • | adverse credit and equity market conditions;

| • | operating costs;

26

| • | competition and demand for our services;

| • | liabilities from operational risks for which we do not have and receive full indemnification or insurance;

| • | governmental regulation;

| • | ability to obtain insurance coverage on commercially reasonable terms;

| • | financial flexibility;

| • | legal proceedings and actions by governmental or other regulatory agencies;

| • | technology-related disputes; and

| • | other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the U.S. Securities and Exchange Commission (the “SEC”).

We caution that the foregoing list of factors is not exhaustive. Additional information concerning these and other risk factors is contained in our Annual Report on Form 10-K for the year ended December 31, 2017 and may be contained in our future filings with the SEC. You are cautioned not to place undue reliance on any of our forward-looking statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to update publicly or revise any of these forward-looking statements, whether as a result of new information, future events or otherwise. In the event that we update any forward-looking statement, no inference should be made that we will make additional updates with respect to that statement, related matters or any other forward-looking statements. All subsequent written and oral forward-looking statements concerning us or other matters and attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements above.

27

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

Recent Developments — On March 27, 2018, we entered into an amended and restated credit agreement, which permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million. See “Liquidity and Capital Resources.”

On February 20, 2018, we acquired the business of Superior QC, LLC (“Superior QC”), including its assets and intellectual property. Superior QC is a provider of software used to improve the accuracy of horizontal wellbore placement. Superior QC’s measurement while drilling (MWD) Survey FDIR (fault detection, isolation and recovery) service is a new data analytics technology to analyze MWD survey data in real-time and more accurately identify the position of the well. Operational and financial data in the discussion and analysis below includes the results of operations of the Superior QC business in our directional drilling segment since February 20, 2018.

On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 3.95% Senior Notes due 2028 (the “2028 Notes”). We used $239 million of the net proceeds from the sale to repay amounts outstanding under our revolving credit facility. The remainder of the proceeds will be used for general corporate purposes.

On October 11, 2017, we acquired all of the issued and outstanding limited liability company interests of MS Directional, LLC (f/k/a Multi-Shot, LLC) (“MS Directional”). The aggregate consideration paid by us consisted of $69.8 million in cash and approximately 8.8 million shares of our common stock. Based on the closing price of our common stock on the closing date of the transaction, the total fair value of the consideration transferred to effect the acquisition of MS Directional was approximately $257 million.

MS Directional is a leading directional drilling services company in the United States, with operations in most major producing onshore oil and gas basins. MS Directional provides a comprehensive suite of directional drilling services, including directional drilling, downhole performance motors, directional surveying, measurement while drilling, and wireline steering tools. Operational and financial data in the discussion and analysis below includes the results of operations of the MS Directional business in our directional drilling segment since October 11, 2017.

On December 12, 2016, we entered into an Agreement and Plan of Merger (the “merger agreement”) with Seventy Seven Energy Inc. (“SSE”). On April 20, 2017, pursuant to the merger agreement, a subsidiary of ours was merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly owned subsidiaries (the “SSE merger”). Pursuant to the terms of the merger agreement, we acquired all of the issued and outstanding shares of common stock of SSE, in exchange for approximately 46.3 million shares of our common stock. Concurrent with the closing of the merger, we repaid all of the outstanding debt of SSE totaling $472 million. Based on the closing price of our common stock on April 20, 2017, the total fair value of the consideration transferred to effect the acquisition of SSE was approximately $1.5 billion. On April 20, 2017, following the SSE merger, SSE was merged with and into our newly-formed subsidiary named Seventy Seven Energy LLC (“SSE LLC”), with SSE LLC continuing as the surviving entity and one of our wholly-owned subsidiaries.

Through the SSE merger, we acquired a fleet of 91 drilling rigs, 36 of which we consider to be APEX® rigs. Additionally, through the SSE merger, we acquired approximately 500,000 horsepower of modern, efficient fracturing equipment located in Oklahoma and Texas. The oilfield rentals business acquired through the SSE merger has a modern, well-maintained fleet of premium oilfield rental tools, and provides specialized services for land-based oil and natural gas drilling, completion and workover activities. Operational and financial data in the discussion and analysis below includes the results of operations of the SSE business since April 20, 2017.

The closing price of oil was as high as $107.95 per barrel in June 2014. Prices began to fall in the third quarter of 2014 and reached a twelve-year low of $26.19 in February 2016. Oil and natural gas prices have recovered from the lows experienced in the first quarter of 2016. Oil prices averaged $62.88 per barrel in the first quarter of 2018.

Our rig count in the United States declined significantly during the industry downturn that began in late 2014, but has improved since the second quarter of 2016. For the first quarter of 2018, our average rig count in the United States improved to 166 rigs, which was an increase from an average of 159 rigs in the fourth quarter of 2017. Term contracts have supported our operating rig count during the last three years. Based on contracts currently in place, we expect an average of 110 rigs operating under term contracts during the second quarter of 2018 and an average of 75 rigs operating under term contracts during the twelve months ending March 31, 2019.

28

Activity level s in our pressure pumping business have also improved. We expect to see further increases in activity across the pressure pumping industry, especially in the Permian Basin. We created our 24 th frac spread early in the second quarter of 2018 utilizing already active horsepower, and w e expect to activate our 25 th frac spread late in the second quarter of 2018, with a substantial amount of the horsepower for this spread coming from already active equipment.

Management Overview — We are a Houston, Texas-based oilfield services company that primarily owns and operates in the United States one of the largest fleets of land-based drilling rigs and a large fleet of pressure pumping equipment. Our contract drilling business operates in the continental United States and western Canada, and we are pursuing contract drilling opportunities outside of North America. Our pressure pumping business operates primarily in Texas and the Mid-Continent and Appalachian regions. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States, and we provide services that improve the accuracy of horizontal wellbore placement. We have other operations through which we provide oilfield rental tools in select markets in the United States, and we also manufacture and sell pipe handling components and related technology to drilling contractors in North America and other select markets. In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located 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, pressure pumping equipment and directional drilling equipment available than necessary to meet demand. As a result, contract drilling, pressure pumping and directional drilling contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods.

Construction of new technology drilling rigs increased significantly in the years preceding the recent industry downturn. 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 activity in unconventional resource plays led to higher demand for pressure pumping services, and there was a significant increase in the construction of new pressure pumping equipment across the industry. As a result of the decline in oil and natural gas prices and the construction of new equipment, there is an excess of drilling rigs, pressure pumping equipment and directional drilling equipment available. In circumstances of excess capacity, providers of contract drilling, pressure pumping and directional drilling 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, pressure pumping or directional drilling services or future conditions in the oil and natural gas contract drilling, pressure pumping or directional drilling businesses.

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 generally weakens, and we experience downward pressure on pricing for our services. While we have seen recent stability and we expect demand for the highest specification drilling rigs to exceed available supply through 2018 and into 2019, there continues to be uncertainty with respect to the global economic environment. Oil and natural gas prices and our average number of rigs operating remain significantly below levels in 2014.

We are also highly impacted by operational risks, competition, the availability of excess equipment, labor issues, weather, the availability of products in our pressure pumping business, supplier delays 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 Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

For the three months ended March 31, 2018 and 2017, our operating revenues consisted of the following (in thousands):

| Three Months Ended March 31, |
| 2018 |  |  | 2017 |
Contract drilling | $ | 327,803 |  |  |  | 40.5 | % |  | $ | 158,728 |  |  |  | 52.0 | %
Pressure pumping |  | 406,784 |  |  |  | 50.3 | % |  |  | 141,174 |  |  |  | 46.3 | %
Directional drilling |  | 48,616 |  |  |  | 6.0 | % |  |  | — |  |  |  | 0.0 | %
Other operations |  | 25,961 |  |  |  | 3.2 | % |  |  | 5,273 |  |  |  | 1.7 | %
| $ | 809,164 |  |  |  | 100.0 | % |  | $ | 305,175 |  |  |  | 100.0 | %

29

Contract Drilling

Contract drilling operations accounted for 40.5% of our consolidated first quarter 2018 revenues, and increased 106.5% over the comparable 2017 period.

Activity in unconventional resource plays has substantially increased and some drilling rigs are not capable of drilling wells in these plays 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 drilling rigs,

| • | refurbishment and upgrades of existing drilling rigs, and

| • | construction of new technology drilling rigs.

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 March 31, 2018, our rig fleet included 198 APEX® rigs. We have customer contracts for all 12 of our previously announced major upgrades. Of these 12, four have been delivered and are included in our current active rig count. The remaining eight rigs receiving major upgrades will be incremental to our current active rig count.

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 contract drilling backlog as of March 31, 2018 was approximately $600 million. Approximately 15% of the total March 31, 2018 backlog is reasonably expected to remain at March 31, 2019. We generally calculate our backlog by multiplying the dayrate 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 or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, our term drilling contracts are generally 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 on which we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the dayrate, for the period over which we expect to receive the lower rate.

Pressure Pumping

Pressure pumping operations accounted for 50.3% of our consolidated first quarter 2018 revenues and increased 188.1% over the comparable 2017 period. As of March 31, 2018, we had approximately 1.6 million horsepower in our pressure pumping fleet. We have increased the horsepower of our pressure pumping fleet by more than thirteen-fold since the beginning of 2009. In recent years, the industry-wide addition of new pressure pumping equipment to the marketplace and lower oil and natural gas prices led to an excess supply of pressure pumping equipment in North America, provided, however, we believe that increased pressure pumping activity in recent months has lessened the oversupply of pressure pumping equipment in the U.S. onshore market.

Directional Drilling

Directional drilling operations accounted for 6.0% of our consolidated first quarter 2018 revenue. Because this activity did not commence until the acquisition of MS Directional in October 2017, there is no corresponding revenue in this segment for the comparable 2017 period. We provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States. Our directional drilling services include directional drilling, downhole performance motors, directional surveying, measurement-while-drilling, and wireline steering tools, and we provide services that improve the accuracy of horizontal wellbore placement.

Other Operations

Other operations revenue accounted for 3.2% of our consolidated first quarter 2018 revenues and increased 392.3% over the comparable 2017 period. Our oilfield rentals business, which was acquired with the SSE merger, provides the largest revenue contribution to our other operations. Our oilfield rentals business has a modern, well-maintained fleet of premium oilfield rental tools, and provides specialized services for land-based oil and natural gas drilling, completion and workover activities.

30

For the three months ended March 31, 2018 and 2017, our operating income (loss) consisted of the following (in thousands):

| Three Months Ended March 31, |
| 2018 |  |  | 2017 |
Contract drilling | $ | (17,103 | ) |  | $ | (61,706 | )
Pressure pumping |  | 25,389 |  |  |  | (22,891 | )
Directional drilling |  | (4,913 | ) |  |  | — |
Other operations |  | (4,089 | ) |  |  | (1,951 | )
Corporate |  | (21,386 | ) |  |  | (6,091 | )
| $ | (22,102 | ) |  | $ | (92,639 | )

Additional discussion of our operating revenues and operating income (loss) follows in the “Results of Operations” section.

On December 22, 2017, significant U.S. tax law changes were enacted (“Tax Reform”). Tax Reform reduced the U.S. federal corporate tax rate from 35% to 21% beginning in 2018, requires companies to pay a one-time transition tax on foreign earnings that were previously tax deferred, creates new taxes on future foreign earnings, places a limitation on the tax deductibility of interest expense, accelerates the expensing of certain business assets, and reduces the amount of executive pay that will be tax deductible, among other changes. See Note 12 of Notes to Unaudited Condensed Consolidated Financial Statements contained in this Report for additional information related to the impact of Tax Reform.

The improvement in demand for our services, offset by the income tax rate change, resulted in a consolidated net loss for the first quarter of 2018 of $34.4 million, compared to a consolidated net loss of $63.5 million for the first quarter of 2017.

Results of Operations

The following tables summarize results of operations by business segment for the three months ended March 31, 2018 and 2017:

Contract Drilling | 2018 |  |  | 2017 |  |  | % Change |
| (dollars in thousands) |  |  |  |  |
Revenues | $ | 327,803 |  |  | $ | 158,728 |  |  |  | 106.5 | %
Direct operating costs |  | 212,583 |  |  |  | 108,221 |  |  |  | 96.4 | %
Margin (1) |  | 115,220 |  |  |  | 50,507 |  |  |  | 128.1 | %
Selling, general and administrative |  | 1,406 |  |  |  | 1,654 |  |  |  | (15.0 | )%
Depreciation and amortization |  | 130,917 |  |  |  | 110,559 |  |  |  | 18.4 | %
Operating loss | $ | (17,103 | ) |  | $ | (61,706 | ) |  |  | (72.3 | )%
Operating days |  | 15,218 |  |  |  | 7,487 |  |  |  | 103.3 | %
Average revenue per operating day | $ | 21.54 |  |  | $ | 21.20 |  |  |  | 1.6 | %
Average direct operating costs per operating day | $ | 13.97 |  |  | $ | 14.45 |  |  |  | (3.3 | )%
Average margin per operating day (1) | $ | 7.57 |  |  | $ | 6.75 |  |  |  | 12.1 | %
Average rigs operating |  | 169 |  |  |  | 83 |  |  |  | 103.6 | %
Capital expenditures | $ | 75,247 |  |  | $ | 44,221 |  |  |  | 70.2 | %

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

Generally, the revenues in our contract drilling segment are most impacted by two primary factors: our average number of rigs operating and our average revenue per operating day. During the first quarter of 2018, our average number of rigs operating was 169, compared to 83 in the first quarter of 2017. Our average rig revenue per operating day was $21,540 in the first quarter of 2018, compared to $21,200 in the first quarter of 2017. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts. Many of our higher day rate, legacy long-term rig contracts were entered into during periods of higher demand, and as a result, these legacy contracts had a higher day rate on average relative to the more recent contracts pursuant to which work was performed during the three months ended March 31, 2018. The majority of these legacy contracts expired during the recent downturn prior to 2018, and as a result we experienced a lower average revenue per operating day during such time. At current commodity prices, we expect to experience increased demand for our services, which could result in higher day rates on newer rig contracts, thus mitigating the reduction in revenue that would result in the future from the continuing expiration of our legacy contracts.

31

Revenues and direct operating costs increased primarily due to an incre ase in operating days. Operating days increased in the quarter primarily due to the recovery in the oil and natural gas industry and the contribution of rigs acquired in the SSE merger. Operating costs also increase d because we increased our head count fa ster than our rig count during the first quarter of 2018 in order to train crews for future rig reactivations. A verage direct operating costs per day decreased primarily due to greater overhead absorption given the larger number of active rigs in the 2018 quarter. Depreciation and amortization increased primarily due to the assets acquired in the SSE merger. Capital expenditures increased over the comparable 2017 quarter due to upgrading rigs to super spec capability, higher maintenance capital expenditu res and other equipment upgrades.

Pressure Pumping | 2018 |  |  | 2017 |  |  | % Change |
| (dollars in thousands) |  |  |  |  |
Revenues | $ | 406,784 |  |  | $ | 141,174 |  |  |  | 188.1 | %
Direct operating costs |  | 320,970 |  |  |  | 119,013 |  |  |  | 169.7 | %
Margin (1) |  | 85,814 |  |  |  | 22,161 |  |  |  | 287.2 | %
Selling, general and administrative |  | 3,903 |  |  |  | 2,802 |  |  |  | 39.3 | %
Depreciation, amortization and impairment |  | 56,522 |  |  |  | 42,250 |  |  |  | 33.8 | %
Operating income (loss) | $ | 25,389 |  |  | $ | (22,891 | ) |  |  | (210.9 | )%
Fracturing jobs |  | 204 |  |  |  | 95 |  |  |  | 114.7 | %
Other jobs |  | 280 |  |  |  | 282 |  |  |  | (0.7 | )%
Total jobs |  | 484 |  |  |  | 377 |  |  |  | 28.4 | %
Average revenue per fracturing job | $ | 1,966.18 |  |  | $ | 1,451.33 |  |  |  | 35.5 | %
Average revenue per other job | $ | 20.30 |  |  | $ | 11.70 |  |  |  | 73.5 | %
Average revenue per total job | $ | 840.46 |  |  | $ | 374.47 |  |  |  | 124.4 | %
Average direct operating costs per total job | $ | 663.16 |  |  | $ | 315.68 |  |  |  | 110.1 | %
Average margin per total job (1) | $ | 177.30 |  |  | $ | 58.78 |  |  |  | 201.6 | %
Margin as a percentage of revenues (1) |  | 21.1 | % |  |  | 15.7 | % |  |  | 34.4 | %
Capital expenditures | $ | 24,923 |  |  | $ | 19,413 |  |  |  | 28.4 | %

(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.

Generally, the revenues in our pressure pumping segment are most impacted by our number of fracturing jobs and the size (including whether or not we provide proppant and other materials) of those jobs, which is reflected in our average revenue per fracturing job. We completed 204 fracturing jobs during the first quarter of 2018 compared to 95 fracturing jobs in the first quarter of 2017. Our average revenue per fracturing job was $1.966 million in the first quarter of 2018 compared to $1.451 million in the first quarter of 2017.

Revenues and direct operating costs during the three months ended March 31, 2018 increased primarily due to an increase in the number and size of fracturing jobs due to the recovery in the oil and natural gas industry and the inclusion of pressure pumping operations acquired from SSE, as compared to the quarter ended March 31, 2017. Depreciation and amortization increased primarily due to the assets acquired in the SSE merger. Average revenue per job increased due to improved pricing and an increase in the size of the jobs. Average direct operating costs per job increased due to the increase in the size of the jobs. Margin as a percentage of revenues improved due to improvements in pricing and economies of scale, as activity levels increased. The increase in capital expenditures was primarily due to higher maintenance capital expenditures as a result of higher activity.

Directional Drilling | 2018 |  |  | 2017 |  |  | % Change
| (in thousands) |  |  |
Revenues | $ | 48,616 |  |  | $ | — |  |  | NA
Direct operating costs |  | 37,689 |  |  |  | — |  |  | NA
Margin (1) |  | 10,927 |  |  |  | — |  |  | NA
Selling, general and administrative |  | 4,938 |  |  |  | — |  |  | NA
Depreciation and amortization |  | 10,902 |  |  |  | — |  |  | NA
Operating loss | $ | (4,913 | ) |  | $ | — |  |  | NA
Capital expenditures | $ | 12,829 |  |  | $ | — |  |  | NA

(1) | Margin is defined as revenues less direct operating costs and excludes depreciation and amortization and selling, general and administrative expenses.

32

Our directional drilling segment originated with the October 11, 2017 acquisition of MS Directional, and consequently we had no results for the first quarter of 2017 in this segment.

Other Operations | 2018 |  |  | 2017 |  |  | % Change |
| (in thousands) |  |  |  |  |
Revenues | $ | 25,961 |  |  | $ | 5,273 |  |  |  | 392.3 | %
Direct operating costs |  | 17,745 |  |  |  | 3,259 |  |  |  | 444.5 | %
Margin (1) |  | 8,216 |  |  |  | 2,014 |  |  |  | 307.9 | %
Selling, general and administrative |  | 2,991 |  |  |  | 1,793 |  |  |  | 66.8 | %
Depreciation, depletion and impairment |  | 9,314 |  |  |  | 2,172 |  |  |  | 328.8 | %
Operating loss | $ | (4,089 | ) |  | $ | (1,951 | ) |  |  | 109.6 | %
Capital expenditures | $ | 9,396 |  |  | $ | 4,352 |  |  |  | 115.9 | %

(1) | Margin is defined as revenues less direct operating costs and excludes depreciation, depletion and impairment and selling, general and administrative expenses.

Revenues, direct operating costs, selling, general and administrative expense and depreciation, depletion and impairment expense from other operations increased primarily as a result of the inclusion of our oilfield rentals business acquired in the SSE merger on April 20, 2017. Depreciation, depletion and impairment expense in 2018 includes approximately $2,000 of oil and natural gas property impairments compared to $503,000 of oil and natural gas property impairments in 2017. The increase in capital expenditures was primarily due to investments in the oilfield rentals business.

Corporate | 2018 |  |  | 2017 |  |  | % Change |
| (in thousands) |  |  |  |  |
Selling, general and administrative | $ | 19,579 |  |  | $ | 12,603 |  |  |  | 55.4 | %
Merger and integration expenses | $ | 1,991 |  |  |  | 5,156 |  |  |  | (61.4 | )%
Depreciation | $ | 2,237 |  |  | $ | 1,236 |  |  |  | 81.0 | %
Other operating income: |  |  |  |  |  |  |  |  |  |  |
Net gain on asset disposals | $ | (10,410 | ) |  | $ | (13,560 | ) |  |  | (23.2 | )%
Legal-related expenses and settlements |  | 5,880 |  |  |  | 656 |  |  |  | 796.3 | %
Research and development |  | 2,109 |  |  |  | — |  |  | NA |
Other operating income | $ | (2,421 | ) |  | $ | (12,904 | ) |  |  | (81.2 | )%
Interest income | $ | 1,423 |  |  | $ | 406 |  |  |  | 250.5 | %
Interest expense | $ | 13,625 |  |  | $ | 8,270 |  |  |  | 64.8 | %
Other income | $ | 169 |  |  | $ | 17 |  |  |  | 894.1 | %
Capital expenditures | $ | 526 |  |  | $ | 454 |  |  |  | 15.9 | %

Selling, general and administrative expense increased in the three months ended March 31, 2018 due to the personnel added as a result of the SSE merger. Merger and integration expenses incurred in 2018 are related to the SSE merger and MS Directional acquisition. Merger and integration expenses incurred in 2017 are related to the SSE merger. Depreciation expense increased in the first quarter of 2018 compared to the same period in 2017 due to the additional corporate assets acquired in the SSE merger. Other operating income includes net gains associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The majority of the net gain on asset disposals during the 2018 period reflects gains on disposal of drilling equipment. The 2017 period included a gain of $11.2 million related to the sale of real estate. Legal-related expenses and settlements includes insurance deductibles and investigation costs related to an accident at a drilling site in January 2018. Research and development expense during 2018 relates to the funding of research into pressure pumping technology. Interest income increased in the three months ended March 31, 2018 due to interest earned on the portion of the proceeds of the January 2018 debt offering that were held as cash during the first quarter of 2018. The debt offering also resulted in an increase in interest expense for the three months ended March 31, 2018.

Income Taxes

Our effective income tax rate for the three months ended March 31, 2018 was (0.8%), compared with 36.8% for the three months ended March 31, 2017. The lower effective income tax rate for the three months ended March 31, 2018 was primarily attributable to the impact of the reduction to the U.S. federal statutory income tax rate and additional limitations for the deductibility of meals and entertainment expenses as a result of Tax Reform. We also recorded a valuation allowance with respect to the deferred tax assets of one of our Canadian subsidiaries due to a change in judgment as to the realizability of these assets.

33

Liquidity and Capital Resources

Our liquidity as of March 31, 2018 included approximately $437 million in working capital, including $304 million of cash and cash equivalents, and approximately $600 million available under our revolving credit facility.

On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 2028 Notes. We used $239 million of the net proceeds from the sale to repay amounts outstanding under our revolving credit facility. The remainder of the proceeds will be used for general corporate purposes. As described below, on March 27, 2018, we entered into an amended and restated credit agreement, which permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million.

We believe our current liquidity, together with cash expected to be generated from operations in 2018, should provide us with sufficient ability to fund our current plans to maintain and make improvements to our existing equipment, service our debt and pay cash dividends for at least the next 12 months. If we pursue opportunities for growth that require capital, 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 or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

During the three months ended March 31, 2018, our sources of cash flow included:

| • | $150 million from operating activities,

| • | $10.3 million in proceeds from the disposal of property and equipment, and

| • | $521 million in proceeds from the issuance of long-term debt.

During the three months ended March 31, 2018, we used $268 million to repay net borrowings under our revolving credit facility, $3.8 million for the acquisition of Superior QC, $4.4 million to pay dividends on our common stock, $4.2 million for debt issuance costs, $16.9 million for the repurchase of our common stock and $123 million:

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

| • | to acquire and procure equipment and facilities to support our drilling, pressure pumping, directional drilling, oilfield rentals and manufacturing operations, and

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

We paid cash dividends during the three months ended March 31, 2018 as follows:

| Per Share |  |  | Total |
|  |  |  |  | (in thousands) |
Paid on March 22, 2018 | $ | 0.02 |  |  | $ | 4,443 |

On April 25, 2018, our Board of Directors approved a cash dividend on our common stock in the amount of $0.04 per share to be paid on June 21, 2018 to holders of record as of June 7, 2018. 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 our debt agreements 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. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. Shares of stock purchased under the plan are held as treasury shares. There is no expiration date associated with the buyback program. As of March 31, 2018, we had remaining authorization to purchase approximately $170 million of our outstanding common stock under the 2013 stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock.

Treasury stock acquisitions during the three months ended March 31, 2018 were as follows (dollars in thousands):

| Shares |  |  | Cost |
Treasury shares at beginning of period |  | 43,802,611 |  |  | $ | 918,711 |
Purchases pursuant to stock buyback program |  | 924,800 |  |  |  | 16,928 |
Treasury shares at end of period |  | 44,727,411 |  |  | $ | 935,639 |

34

Credit Agreement — On March 27, 2018, we entered into an amended and restated credit agreement (the “Credit Agreement”) among us, as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender, each of the other lenders and letter of credit issuers party thereto, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Syndication Agents, Royal Bank of Canada, as Documentation Agent and Wells Fargo Securities, LLC, The Bank of Nova Scotia and U.S. B ank National Association, as Co-Lead Arrangers and Joint Book Runners.

The Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $300 million, not to exceed total commitments of $900 million. The maturity date under the Credit Agreement is March 27, 2023. We have the option, subject to certain conditions, to exercise two one-year extensions of the maturity date.

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 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based upon our credit rating. 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 varies from 0.100% to 0.300% based on our credit rating.

None of our subsidiaries are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt in excess of the Priority Debt Basket (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.

The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe are customary for agreements of this nature, including certain restrictions on our ability and each of our subsidiaries to incur debt and grant liens. If our credit rating is below investment grade, we will become subject to a restricted payment covenant, which would require us to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50%. 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 end of the most recently ended fiscal quarter.

As of March 31, 2018, we had no amounts outstanding million outstanding under our revolving credit facility. We had $81,000 in letters of credit outstanding under our revolving credit facility at March 31, 2018 and, as a result, had available borrowing capacity of approximately $600 million at that date.

2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of March 31, 2018, we had $54.9 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts.

We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015 (the “Continuing Guaranty”), our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.

35

Series A & B Senior Notes — 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 domestic subsidiaries other than subsidiaries that are not required to be guarantors under the Credit Agreement. None of our subsidiaries are currently required to be a guarantor under the Credit Agreement.

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 our 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 March 31, 2018. 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.

2028 Senior Notes — On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 2028 Notes initially guaranteed on a senior unsecured basis by certain of our subsidiaries. These guarantees were automatically released in connection with our entry into the Credit Agreement on March 27, 2018. The net proceeds before offering expenses were approximately $521 million of which we used $239 million to repay amounts outstanding under our revolving credit facility. We intend to use the remainder of the net proceeds for general corporate purposes.

We pay interest on the 2028 Notes on February 1 and August 1 of each year. The 2028 Notes will mature on February 1, 2028. The 2028 Notes bear interest at a rate of 3.95% per annum.

The 2028 Notes are senior unsecured obligations, which rank equally with all of our other existing and future senior unsecured debt and will rank senior in right of payment to all of our other future subordinated debt. The 2028 Notes will be effectively subordinated to any of our future secured debt to the extent of the value of the assets securing such debt. In addition, the 2028 Notes will be structurally subordinated to the liabilities (including trade payables) of our subsidiaries that do not guarantee the 2028 Notes. None of our subsidiaries are currently required to be a guarantor under the 2028 Notes. If our subsidiaries guarantee the 2028 Notes in the future, such guarantees (the “Guarantees”) will rank equally in right of payment with all of the guarantors’ future unsecured senior debt and senior in right of payment to all of the guarantors’ future subordinated debt. The Guarantees will be effectively subordinated to any of the guarantors’ future secured debt to the extent of the value of the assets securing such debt.

36

We, at our option, may redeem the Notes in whole or part, at any time or from time to time at a redemption price equal to 100% of the principal amount of such 2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date, plus a make-whole premium. Additionally, commencing on November 1, 2027, we, at our option, may redeem the 2028 Notes in whole or part, at a redemption price equal to 100% of the principal amount of the 2028 Notes to be redee med, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date.

The indenture pursuant to which the 2028 Notes were issued includes covenants that, among other things, limit our and our subsidiaries’ ability to incur certain liens, engage in sale and lease-back transactions or consolidate, merge, or transfer all or substantially all of their assets. These covenants are subject to important qualifications and limitations set forth in the indenture.

Upon the occurrence of a change of control, as defined in the indenture, each holder of the 2028 Notes may require us to purchase all or a portion of such holder’s 2028 Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.

The indenture also provides for events of default which, if any of them occurs, would permit or require the principal of, premium, if any, and accrued interest, if any, on the 2028 Notes to become or to be declared due and payable.

Commitments and Contingencies — As of March 31, 2018, we maintained letters of credit in the aggregate amount of $55.0 million primarily for the benefit of various insurance companies as collateral for 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 March 31, 2018, no amounts had been drawn under the letters of credit.

As of March 31, 2018, we had commitments to purchase major equipment and make investments totaling approximately $183 million for our drilling, pressure pumping, directional drilling and oilfield rentals businesses.

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. These agreements expire in 2017, 2018, 2021 and 2041. As of March 31, 2018, the remaining obligation under these agreements was approximately $130 million, of which approximately $24.8 million relates to purchases required during the remainder of 2018. In the event the required minimum quantities are not purchased during certain periods, we could be required to make a liquidated damages payment to the respective vendor for any shortfall.

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.

Adjusted EBITDA

Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by accounting principles generally accepted in the United States of America (“U.S. GAAP”). We define Adjusted EBITDA as net income (loss) plus net interest expense, income tax expense (benefit) and depreciation, depletion, amortization and impairment expense (including impairment of goodwill). We present Adjusted EBITDA because we believe it provides to both management and investors additional information with respect to the performance of our fundamental business activities and a comparison of the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be construed as an alternative to the U.S. GAAP measure of net income (loss). Our computations of Adjusted EBITDA may not be the same as other similarly titled measures of other companies. Set forth below is a reconciliation of the non-U.S. GAAP financial measure of Adjusted EBITDA to the U.S. GAAP financial measure of net income (loss).

| Three Months Ended |
| March 31, |
| 2018 |  |  | 2017 |
| (in thousands) |
Net loss | $ | (34,417 | ) |  | $ | (63,539 | )
Income tax expense (benefit) |  | 282 |  |  |  | (36,947 | )
Net interest expense |  | 12,202 |  |  |  | 7,864 |
Depreciation, depletion, amortization and impairment |  | 209,892 |  |  |  | 156,217 |
Adjusted EBITDA | $ | 187,959 |  |  | $ | 63,595 |

37

Critical Accounting Policies

In May 2014, the FASB issued an accounting standard 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. The Company adopted this new revenue guidance effective January 1, 2018 utilizing the modified retrospective method. The adoption of this update did not have a material impact on the Company’s condensed consolidated financial statements.

In addition to established accounting policies, our condensed consolidated financial statements are impacted by certain estimates and assumptions made by management.

Recently Issued Accounting Standards

Please see Note 1 to our unaudited condensed consolidated financial statements for a discussion of recently issued accounting standards.

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 many factors beyond our control. The closing price of oil was as high as $107.95 per barrel in June 2014. Prices began to fall in the third quarter of 2014 and reached a twelve-year low of $26.19 in February 2016. Oil and natural gas prices have recovered from the lows experienced in the first quarter of 2016. Oil prices averaged $62.88 per barrel in the first quarter of 2018.

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. Higher oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices. A decline in demand for oil and natural gas, prolonged low oil or natural gas prices or expectations of decreases in oil and natural gas prices, would likely result in reduced capital expenditures by our customers and decreased demand for our services, which could have a material adverse effect on 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 services.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

As of March 31, 2018, we had exposure to interest rate market risk associated with any borrowings that we had under the Credit Agreement and the Reimbursement Agreement.

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 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based on our credit rating. As of March 31, 2018, the applicable margin on LIBOR rate loans was 1.5% and the applicable margin on base rate loans was 0.5%. As of March 31, 2018, we had no amounts outstanding under our revolving credit facility.

Under the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum. As of March 31, 2018, no amounts had been disbursed under any letters of credit.

We conduct a portion of our business in Canadian dollars. 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.

38

I TEM 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 March 31, 2018.

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.

We completed the acquisition of MS Directional on October 11, 2017, and we are integrating MS Directional into our internal control framework. This integration may lead to changes in our controls in future periods, but management does not expect these changes to materially affect our internal control over financial reporting.

39

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

On January 22, 2018, an accident at a drilling site in Pittsburg County, Oklahoma resulted in the losses of life of five people, including three of our employees. The U.S. Environmental Protection Agency, U.S. Occupational Safety and Health Administration and the U.S. Chemical Safety and Hazard Investigation Board are currently conducting investigations related to this accident. These investigations are ongoing, and we are cooperating with the agencies regarding these investigations. The results of these investigations are not known at this time, and we are unable to determine what finding they might reach, predict what actions these agencies may require or estimate what penalties, if any, they might assess.

Lawsuits have been filed in the District Court for Pittsburg County, Oklahoma in connection with the five individuals who lost their lives in the accident. These lawsuits allege various causes of action against us including negligence, gross negligence, knowledge that injury or death was substantially certain, acting with purpose, recklessness, wrongful death and survival, and the plaintiffs seek an unspecified amount of damages, including punitive or exemplary damages, costs, interest, and other relief. We dispute the plaintiffs’ allegations and intend to defend ourselves vigorously. Based on the information we have available as of the date of this Report, we believe that we have adequate insurance to cover any losses, excluding the applicable insurance deductibles and investigation-related expenses. However, if this accident is not fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Additionally, we are party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

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 March 31, 2018.

|  |  |  |  |  |  |  |  |  |  |  |  |  | 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) |
January 2018 |  |  | — |  |  | $ | — |  |  |  | — |  |  |  | 186,544 |
February 2018 |  |  | 300,500 |  |  | $ | 18.06 |  |  |  | 300,500 |  |  |  | 181,117 |
March 2018 |  |  | 624,300 |  |  | $ | 18.42 |  |  |  | 624,300 |  |  |  | 169,616 |
Total |  |  | 924,800 |  |  |  |  |  |  |  | 924,800 |  |  |  | 169,616 |

(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. All purchases executed to date have been through open market transactions. Purchases under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. Shares of stock purchased under the plan are held as treasury shares. There is no expiration date associated with the buyback program.

40

I TEM 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 |  | Certificate of 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 |  | Certificate of Elimination with respect to Series A Participating Preferred Stock (filed October 27, 2011 as Exhibit 3.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
3.4 |  | 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).
4.1 |  | Base Indenture, dated January 19, 2018, among Patterson-UTI Energy, Inc., the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed January 19, 2018 as Exhibit 4.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
4.2 |  | First Supplemental Indenture, dated January 19, 2018, among Patterson-UTI Energy, Inc., the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed January 19, 2018 as Exhibit 4.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
4.3 |  | Form of 3.95% Senior Note due 2028 (included in Exhibit 4.2 above).
4.4 |  | Registration Rights Agreement, dated January 19, 2018, among Patterson-UTI Energy, Inc., the several guarantors named therein and Goldman, Sachs & Co. LLC, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated (filed January 19, 2018 as Exhibit 4.4 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
10.1 |  | Amended and Restated Credit Agreement dated March 27, 2018 among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuers and lenders party thereto (filed March 27, 2018 as Exhibit 10.1 to the Company’s Current Report on Form 8-K 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 March 31, 2018, formatted in XBRL (Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income (Loss), (iv) the Condensed Consolidated Statement of Changes in Stockholders’ Equity, (v) the Condensed Consolidated Statements of Cash Flows, and (vi) Notes to Condensed Consolidated Financial Statements.

* | filed herewith

41

S IGNATURE

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/ C. Andrew Smith
|  | C. Andrew Smith
|  | Executive Vice President and
|  | Chief Financial Officer
|  | (Principal Financial and Accounting Officer and Duly Authorized Officer)

Date: May 1, 2018

42