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 SeptemberJune 30, 20172019
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 |
| (I.R.S. Employer |
|
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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)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol | Name of each exchange on which registered | ||
Common Stock, $0.01 Par Value | PTEN | The Nasdaq Global Select Market |
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, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
Large accelerated filer |
| ☑ |
| Accelerated filer |
| ☐ |
| Smaller reporting company |
| ☐ |
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| |||
Non-accelerated filer |
| ☐ |
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| 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.
222,444,317202,606,846 shares of common stock, $0.01 par value, as of October 30, 2017
July 25, 2019
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
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ITEM 1. |
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| Unaudited condensed consolidated statements of comprehensive loss |
| 5 |
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| Unaudited condensed consolidated |
| 6 |
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| Notes to unaudited condensed consolidated financial statements |
| 8 |
ITEM 2. |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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ITEM 3. |
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ITEM 4. |
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ITEM 1. |
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ITEM 2. |
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ITEM 6. |
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PART I — FINANCIAL INFORMATION
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)
| June 30, |
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| December 31, |
| ||
| 2019 |
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| 2018 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents | $ | 255,514 |
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| $ | 245,029 |
|
Accounts receivable, net of allowance for doubtful accounts of $5,901 and $2,312 at June 30, 2019 and December 31, 2018, respectively |
| 501,206 |
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| 558,817 |
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Federal and state income taxes receivable |
| 5,954 |
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| 4,110 |
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Inventory |
| 68,611 |
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| 65,579 |
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Other |
| 66,459 |
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| 76,662 |
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Total current assets |
| 897,744 |
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| 950,197 |
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Property and equipment, net |
| 3,769,258 |
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| 4,002,549 |
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Right of use asset |
| 26,665 |
|
|
| — |
|
Goodwill and intangible assets |
| 472,413 |
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|
| 477,640 |
|
Deposits on equipment purchases |
| 7,312 |
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|
| 12,040 |
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Other |
| 18,391 |
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| 27,440 |
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Total assets | $ | 5,191,783 |
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| $ | 5,469,866 |
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LIABILITIES AND STOCKHOLDERS' EQUITY |
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Current liabilities: |
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Accounts payable | $ | 242,166 |
|
| $ | 288,962 |
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Federal and state income taxes payable |
| 269 |
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|
| 1,408 |
|
Accrued liabilities |
| 218,632 |
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|
| 235,946 |
|
Lease liability |
| 8,977 |
|
|
| — |
|
Total current liabilities |
| 470,044 |
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| 526,316 |
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Long-term lease liability |
| 22,355 |
|
|
| — |
|
Long-term debt, net of debt discount and issuance costs of $5,352 and $5,795 at June 30, 2019 and December 31, 2018, respectively |
| 1,119,648 |
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| 1,119,205 |
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Deferred tax liabilities, net |
| 291,294 |
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| 306,161 |
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Other |
| 10,131 |
|
|
| 12,761 |
|
Total liabilities |
| 1,913,472 |
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| 1,964,443 |
|
Commitments and contingencies (see Note 10) |
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Stockholders' equity: |
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Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued |
| — |
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| — |
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Common stock, par value $.01; authorized 400,000,000 shares with 268,790,705 and 267,315,526 issued and 202,401,130 and 213,614,430 outstanding at June 30, 2019 and December 31, 2018, respectively |
| 2,688 |
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|
| 2,673 |
|
Additional paid-in capital |
| 2,856,746 |
|
|
| 2,827,154 |
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Retained earnings |
| 1,658,417 |
|
|
| 1,753,557 |
|
Accumulated other comprehensive income |
| 4,279 |
|
|
| 2,487 |
|
Treasury stock, at cost, 66,389,575 and 53,701,096 shares at June 30, 2019 and December 31, 2018, respectively |
| (1,243,819 | ) |
|
| (1,080,448 | ) |
Total stockholders' equity |
| 3,278,311 |
|
|
| 3,505,423 |
|
Total liabilities and stockholders' equity | $ | 5,191,783 |
|
| $ | 5,469,866 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands, except per share data)
| September 30, |
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| December 31, |
| ||
| 2017 |
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| 2016 |
| ||
ASSETS |
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Current assets: |
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Cash and cash equivalents | $ | 37,839 |
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| $ | 35,152 |
|
Accounts receivable, net of allowance for doubtful accounts of $3,116 and $3,191 at September 30, 2017 and December 31, 2016, respectively |
| 544,509 |
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| 148,091 |
|
Federal and state income taxes receivable |
| 630 |
|
|
| 2,126 |
|
Inventory |
| 40,672 |
|
|
| 20,191 |
|
Other |
| 54,647 |
|
|
| 41,322 |
|
Total current assets |
| 678,297 |
|
|
| 246,882 |
|
Property and equipment, net |
| 4,198,285 |
|
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| 3,408,963 |
|
Goodwill and intangible assets |
| 533,682 |
|
|
| 88,966 |
|
Deposits on equipment purchases |
| 15,027 |
|
|
| 16,050 |
|
Deferred tax assets, net |
| 2,562 |
|
|
| 4,124 |
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Other |
| 45,122 |
|
|
| 7,306 |
|
Total assets | $ | 5,472,975 |
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| $ | 3,772,291 |
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
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Current liabilities: |
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Accounts payable | $ | 303,522 |
|
| $ | 125,667 |
|
Accrued expenses |
| 245,826 |
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| 139,148 |
|
Total current liabilities |
| 549,348 |
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| 264,815 |
|
Borrowings under revolving credit facility |
| 144,000 |
|
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| — |
|
Long-term debt, net of debt issuance cost of $1,303 and $1,563 at September 30, 2017 and December 31, 2016, respectively |
| 598,697 |
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| 598,437 |
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Deferred tax liabilities, net |
| 576,312 |
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| 650,661 |
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Other |
| 11,416 |
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| 9,654 |
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Total liabilities |
| 1,879,773 |
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| 1,523,567 |
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Commitments and contingencies (see Note 10) |
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Stockholders' equity: |
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Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued |
| — |
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| — |
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Common stock, par value $.01; authorized 300,000,000 shares with 257,428,497 and 191,525,872 issued and 213,652,526 and 148,133,255 outstanding at September 30, 2017 and December 31, 2016, respectively |
| 2,574 |
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| 1,915 |
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Additional paid-in capital |
| 2,588,327 |
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| 1,042,696 |
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Retained earnings |
| 1,914,966 |
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| 2,116,341 |
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Accumulated other comprehensive income (loss) |
| 5,461 |
|
|
| (1,134 | ) |
Treasury stock, at cost, 43,775,971 and 43,392,617 shares at September 30, 2017 and December 31, 2016, respectively |
| (918,126 | ) |
|
| (911,094 | ) |
Total stockholders' equity |
| 3,593,202 |
|
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| 2,248,724 |
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Total liabilities and stockholders' equity | $ | 5,472,975 |
|
| $ | 3,772,291 |
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| Three Months Ended |
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| Six Months Ended |
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| June 30, |
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| June 30, |
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| 2019 |
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| 2018 |
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| 2019 |
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| 2018 |
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Operating revenues: |
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Contract drilling | $ | 348,138 |
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| $ | 349,922 |
|
| $ | 720,530 |
|
| $ | 677,725 |
|
Pressure pumping |
| 251,008 |
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|
| 425,303 |
|
|
| 498,609 |
|
|
| 832,087 |
|
Directional drilling |
| 50,218 |
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|
| 52,705 |
|
|
| 103,177 |
|
|
| 101,321 |
|
Other |
| 26,401 |
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|
| 26,488 |
|
|
| 57,620 |
|
|
| 52,449 |
|
Total operating revenues |
| 675,765 |
|
|
| 854,418 |
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|
| 1,379,936 |
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| 1,663,582 |
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Operating costs and expenses: |
|
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|
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Contract drilling |
| 201,792 |
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| 217,674 |
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| 420,994 |
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|
| 430,257 |
|
Pressure pumping |
| 206,137 |
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| 342,885 |
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| 408,885 |
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| 663,855 |
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Directional drilling |
| 42,102 |
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|
| 43,685 |
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|
| 87,704 |
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|
| 81,374 |
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Other |
| 17,612 |
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|
| 17,513 |
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| 39,385 |
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|
| 35,258 |
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Depreciation, depletion, amortization and impairment |
| 208,688 |
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|
| 212,384 |
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|
| 423,098 |
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|
| 422,276 |
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Selling, general and administrative |
| 34,894 |
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|
| 35,663 |
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|
| 67,449 |
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|
| 68,480 |
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Provision for bad debts |
| 3,594 |
|
|
| — |
|
|
| 3,594 |
|
|
| — |
|
Merger and integration expenses |
| — |
|
|
| 747 |
|
|
| — |
|
|
| 2,738 |
|
Other operating expenses (income), net |
| 9,071 |
|
|
| (7,129 | ) |
|
| 335 |
|
|
| (9,550 | ) |
Total operating costs and expenses |
| 723,890 |
|
|
| 863,422 |
|
|
| 1,451,444 |
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|
| 1,694,688 |
|
Operating loss |
| (48,125 | ) |
|
| (9,004 | ) |
|
| (71,508 | ) |
|
| (31,106 | ) |
|
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Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Interest income |
| 1,756 |
|
|
| 2,360 |
|
|
| 2,788 |
|
|
| 3,783 |
|
Interest expense, net of amount capitalized |
| (13,298 | ) |
|
| (12,667 | ) |
|
| (26,282 | ) |
|
| (26,292 | ) |
Other |
| 92 |
|
|
| 216 |
|
|
| 209 |
|
|
| 385 |
|
Total other expense |
| (11,450 | ) |
|
| (10,091 | ) |
|
| (23,285 | ) |
|
| (22,124 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Loss before income taxes |
| (59,575 | ) |
|
| (19,095 | ) |
|
| (94,793 | ) |
|
| (53,230 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Income tax benefit |
| (10,128 | ) |
|
| (8,382 | ) |
|
| (16,732 | ) |
|
| (8,100 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss | $ | (49,447 | ) |
| $ | (10,713 | ) |
| $ | (78,061 | ) |
| $ | (45,130 | ) |
|
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Net loss per common share: |
|
|
|
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|
|
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Basic | $ | (0.24 | ) |
| $ | (0.05 | ) |
| $ | (0.37 | ) |
| $ | (0.21 | ) |
Diluted | $ | (0.24 | ) |
| $ | (0.05 | ) |
| $ | (0.37 | ) |
| $ | (0.21 | ) |
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Weighted average number of common shares outstanding: |
|
|
|
|
|
|
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|
|
|
|
|
|
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Basic |
| 207,499 |
|
|
| 220,093 |
|
|
| 209,671 |
|
|
| 220,436 |
|
Diluted |
| 207,499 |
|
|
| 220,093 |
|
|
| 209,671 |
|
|
| 220,436 |
|
Cash dividends per common share | $ | 0.04 |
|
| $ | 0.04 |
|
| $ | 0.08 |
|
| $ | 0.06 |
|
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 OPERATIONSCOMPREHENSIVE LOSS
(unaudited, in thousands, except per share data)thousands)
| Three Months Ended |
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| Nine Months Ended |
| ||||||||||
| September 30, |
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| September 30, |
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| 2017 |
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| 2016 |
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| 2017 |
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| 2016 |
| ||||
Operating revenues: |
|
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|
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Contract drilling | $ | 301,614 |
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| $ | 123,684 |
|
| $ | 730,453 |
|
| $ | 407,578 |
|
Pressure pumping |
| 362,441 |
|
|
| 78,165 |
|
|
| 793,659 |
|
|
| 248,428 |
|
Other |
| 20,934 |
|
|
| 4,284 |
|
|
| 45,238 |
|
|
| 12,973 |
|
Total operating revenues |
| 684,989 |
|
|
| 206,133 |
|
|
| 1,569,350 |
|
|
| 668,979 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Contract drilling |
| 186,957 |
|
|
| 74,517 |
|
|
| 475,836 |
|
|
| 219,218 |
|
Pressure pumping |
| 290,315 |
|
|
| 77,221 |
|
|
| 643,228 |
|
|
| 234,580 |
|
Other |
| 15,882 |
|
|
| 1,846 |
|
|
| 31,812 |
|
|
| 5,586 |
|
Depreciation, depletion, amortization and impairment |
| 196,642 |
|
|
| 163,464 |
|
|
| 572,187 |
|
|
| 511,209 |
|
Selling, general and administrative |
| 27,551 |
|
|
| 16,612 |
|
|
| 69,881 |
|
|
| 51,671 |
|
Merger and integration expenses |
| 9,449 |
|
|
| — |
|
|
| 65,798 |
|
|
| — |
|
Other operating income, net |
| (3,791 | ) |
|
| (4,118 | ) |
|
| (18,501 | ) |
|
| (10,285 | ) |
Total operating costs and expenses |
| 723,005 |
|
|
| 329,542 |
|
|
| 1,840,241 |
|
|
| 1,011,979 |
|
Operating loss |
| (38,016 | ) |
|
| (123,409 | ) |
|
| (270,891 | ) |
|
| (343,000 | ) |
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
| 101 |
|
|
| 63 |
|
|
| 1,149 |
|
|
| 273 |
|
Interest expense, net of amount capitalized |
| (9,584 | ) |
|
| (10,244 | ) |
|
| (26,929 | ) |
|
| (31,722 | ) |
Other |
| 78 |
|
|
| 19 |
|
|
| 226 |
|
|
| 52 |
|
Total other expense |
| (9,405 | ) |
|
| (10,162 | ) |
|
| (25,554 | ) |
|
| (31,397 | ) |
Loss before income taxes |
| (47,421 | ) |
|
| (133,571 | ) |
|
| (296,445 | ) |
|
| (374,397 | ) |
Income tax benefit |
| (13,652 | ) |
|
| (49,428 | ) |
|
| (106,953 | ) |
|
| (133,885 | ) |
Net loss | $ | (33,769 | ) |
| $ | (84,143 | ) |
| $ | (189,492 | ) |
| $ | (240,512 | ) |
Net loss per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic | $ | (0.16 | ) |
| $ | (0.58 | ) |
| $ | (0.99 | ) |
| $ | (1.65 | ) |
Diluted | $ | (0.16 | ) |
| $ | (0.58 | ) |
| $ | (0.99 | ) |
| $ | (1.65 | ) |
Weighted average number of common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| 211,875 |
|
|
| 146,326 |
|
|
| 191,237 |
|
|
| 146,014 |
|
Diluted |
| 211,875 |
|
|
| 146,326 |
|
|
| 191,237 |
|
|
| 146,014 |
|
Cash dividends per common share | $ | 0.02 |
|
| $ | 0.02 |
|
| $ | 0.06 |
|
| $ | 0.14 |
|
| Three Months Ended |
|
| Six Months Ended |
| ||||||||||
| June 30, |
|
| June 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
Net loss | $ | (49,447 | ) |
| $ | (10,713 | ) |
| $ | (78,061 | ) |
| $ | (45,130 | ) |
Other comprehensive income (loss), net of taxes of $0 for all periods: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment |
| 848 |
|
|
| (1,530 | ) |
|
| 1,792 |
|
|
| (3,514 | ) |
Total comprehensive loss | $ | (48,599 | ) |
| $ | (12,243 | ) |
| $ | (76,269 | ) |
| $ | (48,644 | ) |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS 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, 2018 |
| 267,316 |
|
| $ | 2,673 |
|
| $ | 2,827,154 |
|
| $ | 1,753,557 |
|
| $ | 2,487 |
|
| $ | (1,080,448 | ) |
| $ | 3,505,423 |
|
Net loss |
| — |
|
|
| — |
|
|
| — |
|
|
| (78,061 | ) |
|
| — |
|
|
| — |
|
|
| (78,061 | ) |
Foreign currency translation adjustment |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,792 |
|
|
| — |
|
|
| 1,792 |
|
Exercise of stock options |
| 700 |
|
|
| 7 |
|
|
| 9,212 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 9,219 |
|
Vesting of restricted stock units |
| 777 |
|
|
| 8 |
|
|
| (8 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Forfeitures of restricted stock |
| (2 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
| — |
|
|
| — |
|
|
| 20,388 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 20,388 |
|
Payment of cash dividends |
| — |
|
|
| — |
|
|
| — |
|
|
| (16,843 | ) |
|
| — |
|
|
| — |
|
|
| (16,843 | ) |
Dividend equivalents |
| — |
|
|
| — |
|
|
| — |
|
|
| (236 | ) |
|
| — |
|
|
| — |
|
|
| (236 | ) |
Purchase of treasury stock |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (163,371 | ) |
|
| (163,371 | ) |
Balance, June 30, 2019 |
| 268,791 |
|
| $ | 2,688 |
|
| $ | 2,856,746 |
|
| $ | 1,658,417 |
|
| $ | 4,279 |
|
| $ | (1,243,819 | ) |
| $ | 3,278,311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 |
| — |
|
|
| — |
|
|
| — |
|
|
| (45,130 | ) |
|
| — |
|
|
| — |
|
|
| (45,130 | ) |
Foreign currency translation adjustment |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (3,514 | ) |
|
| — |
|
|
| (3,514 | ) |
Exercise of stock options |
| 40 |
|
|
| 1 |
|
|
| 484 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 485 |
|
Issuance of common stock |
| 381 |
|
|
| 4 |
|
|
| (4 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Vesting of restricted stock units |
| 10 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Forfeitures of restricted stock |
| (2 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
| — |
|
|
| — |
|
|
| 19,272 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 19,272 |
|
Payment of cash dividends |
| — |
|
|
| — |
|
|
| — |
|
|
| (13,275 | ) |
|
| — |
|
|
| — |
|
|
| (13,275 | ) |
Dividend equivalents |
| — |
|
|
| — |
|
|
| — |
|
|
| (113 | ) |
|
| — |
|
|
| — |
|
|
| (113 | ) |
Purchase of treasury stock |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (59,879 | ) |
|
| (59,879 | ) |
Balance, June 30, 2018 |
| 266,688 |
|
| $ | 2,667 |
|
| $ | 2,805,575 |
|
| $ | 2,047,379 |
|
| $ | 3,308 |
|
| $ | (978,590 | ) |
| $ | 3,880,339 |
|
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 |
|
| Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
Net loss | $ | (33,769 | ) |
| $ | (84,143 | ) |
| $ | (189,492 | ) |
| $ | (240,512 | ) |
Other comprehensive income (loss), net of taxes of $0 for all periods: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment |
| 3,607 |
|
|
| (2,379 | ) |
|
| 6,595 |
|
|
| 4,768 |
|
Total comprehensive loss | $ | (30,162 | ) |
| $ | (86,522 | ) |
| $ | (182,897 | ) |
| $ | (235,744 | ) |
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, 2016 |
| 191,526 |
|
| $ | 1,915 |
|
| $ | 1,042,696 |
|
| $ | 2,116,341 |
|
| $ | (1,134 | ) |
| $ | (911,094 | ) |
|
| 2,248,724 |
|
Net loss |
| — |
|
|
| — |
|
|
| — |
|
|
| (189,492 | ) |
|
| — |
|
|
| — |
|
|
| (189,492 | ) |
Foreign currency translation adjustment |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 6,595 |
|
|
| — |
|
|
| 6,595 |
|
Equity offering |
| 18,170 |
|
|
| 182 |
|
|
| 471,388 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 471,570 |
|
Shares issued for acquisition |
| 46,298 |
|
|
| 463 |
|
|
| 1,038,933 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,039,396 |
|
Exercise of stock options |
| 10 |
|
|
| — |
|
|
| 223 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 223 |
|
Issuance of restricted stock |
| 891 |
|
|
| 9 |
|
|
| (9 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Vesting of restricted stock units |
| 549 |
|
|
| 5 |
|
|
| (5 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Forfeitures of restricted stock |
| (16 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
| — |
|
|
| — |
|
|
| 35,101 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 35,101 |
|
Payment of cash dividends |
| — |
|
|
| — |
|
|
| — |
|
|
| (11,866 | ) |
|
| — |
|
|
| — |
|
|
| (11,866 | ) |
Dividend equivalents |
| — |
|
|
| — |
|
|
| — |
|
|
| (17 | ) |
|
| — |
|
|
| — |
|
|
| (17 | ) |
Purchase of treasury stock |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (7,032 | ) |
|
| (7,032 | ) |
Balance, September 30, 2017 |
| 257,428 |
|
| $ | 2,574 |
|
| $ | 2,588,327 |
|
| $ | 1,914,966 |
|
| $ | 5,461 |
|
| $ | (918,126 | ) |
| $ | 3,593,202 |
|
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)
| Nine Months Ended |
| Six Months Ended |
| ||||||||||
| September 30, |
| June 30, |
| ||||||||||
| 2017 |
|
| 2016 |
| 2019 |
|
| 2018 |
| ||||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss | $ | (189,492 | ) |
| $ | (240,512 | ) | $ | (78,061 | ) |
| $ | (45,130 | ) |
Adjustments to reconcile net loss to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and impairment |
| 572,187 |
|
|
| 511,209 |
|
| 423,098 |
|
|
| 422,276 |
|
Dry holes and abandonments |
| 443 |
|
|
| — |
|
| 94 |
|
|
| 562 |
|
Deferred income tax benefit |
| (104,190 | ) |
|
| (109,045 | ) |
| (14,867 | ) |
|
| (8,100 | ) |
Stock-based compensation expense |
| 35,101 |
|
|
| 21,130 |
|
| 20,388 |
|
|
| 19,272 |
|
Net gain on asset disposals |
| (19,079 | ) |
|
| (9,808 | ) |
| (10,516 | ) |
|
| (17,472 | ) |
Tax expense on stock-based compensation |
| — |
|
|
| (4,895 | ) | |||||||
Amortization of debt issuance costs |
| 260 |
|
|
| 2,184 |
| |||||||
Writedown of capacity reservation contract |
| 12,673 |
|
|
| — |
| |||||||
Provision for bad debts |
| 3,594 |
|
|
| — |
| |||||||
Amortization of debt discount and issuance costs |
| 443 |
|
|
| 387 |
| |||||||
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
| (246,407 | ) |
|
| 74,742 |
|
| 54,188 |
|
|
| (22,363 | ) |
Income taxes receivable |
| 1,499 |
|
|
| 28,524 |
| |||||||
Income taxes receivable/payable |
| (2,972 | ) |
|
| (22 | ) | |||||||
Inventory and other assets |
| (26,398 | ) |
|
| 7,876 |
|
| (3,967 | ) |
|
| (25,277 | ) |
Accounts payable |
| 91,499 |
|
|
| (19,652 | ) |
| (16,941 | ) |
|
| (23,432 | ) |
Accrued expenses |
| 15,917 |
|
|
| (7,616 | ) | |||||||
Accrued liabilities |
| (18,884 | ) |
|
| (542 | ) | |||||||
Other liabilities |
| (75 | ) |
|
| (1,431 | ) |
| (2,971 | ) |
|
| 76 |
|
Net cash provided by operating activities |
| 131,265 |
|
|
| 252,706 |
|
| 365,299 |
|
|
| 300,235 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition, net of cash acquired |
| (434,194 | ) |
|
| 155 |
| |||||||
Acquisitions, net of cash acquired |
| (13 | ) |
|
| (3,800 | ) | |||||||
Purchases of property and equipment |
| (329,851 | ) |
|
| (80,511 | ) |
| (215,260 | ) |
|
| (317,783 | ) |
Proceeds from disposal of assets |
| 39,672 |
|
|
| 18,384 |
| |||||||
Other investments |
| (2,520 | ) |
|
| — |
| |||||||
Proceeds from disposal of assets and insurance claims |
| 31,516 |
|
|
| 21,005 |
| |||||||
Collection of note receivable |
| — |
|
|
| 23,760 |
| |||||||
Net cash used in investing activities |
| (726,893 | ) |
|
| (61,972 | ) |
| (183,757 | ) |
|
| (276,818 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from equity offering |
| 471,570 |
|
|
| — |
| |||||||
Purchases of treasury stock |
| (6,809 | ) |
|
| (3,611 | ) |
| (154,152 | ) |
|
| (59,879 | ) |
Proceeds from exercise of options |
| — |
|
|
| 485 |
| |||||||
Dividends paid |
| (11,866 | ) |
|
| (20,618 | ) |
| (16,843 | ) |
|
| (13,275 | ) |
Debt issuance costs |
| — |
|
|
| (3,357 | ) |
| — |
|
|
| (4,333 | ) |
Repayment of long-term debt |
| — |
|
|
| (255,000 | ) | |||||||
Proceeds from long-term debt |
| — |
|
|
| 521,194 |
| |||||||
Proceeds from borrowings under revolving credit facility |
| 282,000 |
|
|
| 95,000 |
|
| — |
|
|
| 79,000 |
|
Repayment of borrowings under revolving credit facility |
| (138,000 | ) |
|
| (80,000 | ) |
| — |
|
|
| (347,000 | ) |
Net cash provided by (used in) financing activities |
| 596,895 |
|
|
| (267,586 | ) | |||||||
Net cash provided by financing activities |
| (170,995 | ) |
|
| 176,192 |
| |||||||
Effect of foreign exchange rate changes on cash |
| 1,420 |
|
|
| 478 |
|
| (62 | ) |
|
| (529 | ) |
Net increase (decrease) in cash and cash equivalents |
| 2,687 |
|
|
| (76,374 | ) | |||||||
Net increase in cash and cash equivalents |
| 10,485 |
|
|
| 199,080 |
| |||||||
Cash and cash equivalents at beginning of period |
| 35,152 |
|
|
| 113,346 |
|
| 245,029 |
|
|
| 42,828 |
|
Cash and cash equivalents at end of period | $ | 37,839 |
|
| $ | 36,972 |
| $ | 255,514 |
|
| $ | 241,908 |
|
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (paid) received during the period for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest, net of capitalized interest of $781 in 2017 and $327 in 2016 | $ | (18,336 | ) |
| $ | (21,973 | ) | |||||||
Interest, net of capitalized interest of $380 in 2019 and $722 in 2018 | $ | (24,924 | ) |
| $ | (15,573 | ) | |||||||
Income taxes | $ | 3,866 |
|
| $ | 44,987 |
|
| (1,127 | ) |
|
| 21 |
|
Non-cash investing and financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in payables for purchases of property and equipment | $ | 48,919 |
|
| $ | 16,884 |
| |||||||
Issuance of common stock for business acquisition | $ | 1,039,396 |
|
|
| 6,733 |
| |||||||
Net decrease in deposits on equipment purchases | $ | 1,023 |
|
| $ | 4,667 |
| |||||||
Receivable from property and equipment insurance | $ | — |
|
| $ | 15,000 |
| |||||||
Net increase (decrease) in payables for purchases of property and equipment |
| (29,935 | ) |
|
| 75,032 |
| |||||||
Net (increase) decrease in deposits on equipment purchases |
| 4,728 |
|
|
| (5,419 | ) | |||||||
Cashless exercise of stock options |
| 9,219 |
|
|
| — |
|
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 Consolidation and 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.subsidiaries (collectively referred to herein as the “Company”). All significant intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries, the Company has no controlling financial interests in any other entity which would require consolidation. As used in these notes, “the Company” refers collectively to Patterson-UTI Energy, Inc. and its consolidated subsidiaries. Patterson-UTI Energy, Inc. conducts its business operations through its wholly-owned subsidiaries and has no employees or independent operations.
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.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, 2016,2018, 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, 2016.2018. The results of operations for the three months and ninesix months ended SeptemberJune 30, 20172019 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 itstheir functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive loss,income, which is a separate component of stockholders’ equity.
Recently Adopted Accounting Standards – In 2017,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. The requirements in this update are effective during interim and annual periods beginning after December 15, 2018. The Company adopted this new leasing guidance effective January 1, 2019 and expanded its consolidated financial statement disclosures in order to comply with the update (See Note 4).
In August 2016, the FASB issued an accounting standards update to clarify the presentation of deferredcash 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.
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 financial statements.
In March 2018, the FASB issued an accounting standards update to update the income tax liabilitiesaccounting 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 “H.R.1,” also known as the “Tax Cuts and assets and such guidance was applied retrospectively, resultingJobs Act” (“U.S. Tax Reform”). The adoption of this update in March 2018 did not have a material impact on the reclassification of $36.4 million from current deferred tax assets as of December 31, 2016. Of this amount, $4.1 million was reclassified to long-term deferred tax assets and $32.3 million was reclassified to long-term deferred tax liabilities. During the fourth quarter of 2016, the Company changed its reporting segment presentation,Company’s consolidated financial statements, as the Company no longer considerswas already following the SEC guidance (See Note 13).
Recently Issued Accounting Standards – In June 2016, the FASB issued an accounting standards update on measurement of credit losses on financial instruments. This update improves financial reporting by requiring earlier recognition of credit losses on financing receivables and other financial assets in scope by using the Current Expected Credit Losses model (CECL). This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The Company is currently evaluating the impact this new guidance will have on its consolidated financial statements.
In August 2018, the FASB issued an accounting standards update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amendments in the update are effective for public business entities for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company is currently evaluating the impact this new guidance will have on its consolidated financial statements.
In August 2018, the FASB issued an accounting standards update to eliminate certain disclosure requirements for fair value measurements for all entities, require public entities to disclose certain new information and modify certain disclosure requirements. The FASB developed the amendments to Topic 820 as part of its broader disclosure framework project, which aims to improve the effectiveness of disclosures in the notes to financial statements by focusing on requirements that clearly communicate the most important information to users of the financial statements. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The Company is currently evaluating the impact this new guidance will have on its consolidated financial statements.
2. Acquisitions
Superior QC, LLC (“Superior QC”)
On February 20, 2018, the Company acquired the business of Superior QC, including its assets and intellectual property. Superior QC is a provider of software and services used to improve the statistical accuracy of horizontal wellbore placement. Superior QC’s measurement-while-drilling (MWD) survey fault detection, isolation and recovery (FDIR) service is a data analytics technology to analyze MWD survey data in real-time and more accurately identify the position of a well. This acquisition was not material to the Company’s consolidated financial statements.
Current Power Solutions, Inc. (“Current Power”)
On October 25, 2018, the Company acquired Current Power. Current Power is a provider of electrical controls and automation to the energy, marine and mining industries. This acquisition was not material to the Company’s consolidated financial statements.
3. Revenues
ASC Topic 606 Revenue from Contracts with Customers
The Company’s contracts with customers include both long-term and short-term contracts. Services that primarily generate revenue earned for the Company include the operating business segments of contract drilling, pressure pumping and directional drilling, which 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, electrical controls and automation, and oil and natural gas explorationworking interests. For more information on the Company’s business segments, including disaggregated revenue recognized from contracts with customers, see Note 15.
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 production activitiesthe 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.
The transaction price is the amount of consideration to which the Company expects to be significantentitled in exchange for transferring promised goods or services to an understandinga customer, based on terms of the Company’s results. contracts with its customers. The consideration promised in a contract with a customer 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 the 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 must 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 for 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.
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 now presents theis a working interest owner of oil and natural gas explorationproperties located in Texas and production activities, oilfield rental tool business, pipe handling componentsNew Mexico. The ownership terms are outlined in joint operating agreements for each well between the operator and related technology business and Middle East/North Africa activities as “Other,” and “Corporate” reflects only corporate activities. This change in segment presentation was applied retrospectively to all periods presented herein (See Note 6).
On December 12, 2016,the various interest owners, including the Company, entered into an Agreementwho 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 Plangas properties does not fall under the scope of Merger (the “merger agreement”) with Seventy Seven Energy Inc. (“SSE”),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 merger closed on April 20, 2017 (the “merger date”).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.
Accounts Receivable and Contract Liabilities
Accounts receivable is the Company’s resultsright to consideration once it becomes unconditional. Payment terms typically range from 30 to 60 days.
Accounts receivable balances were $497 million and $554 million as of June 30, 2019 and December 31, 2018, respectively. These balances do not include amounts related to the results of operations of SSE sinceCompany’s oil and gas working interests as those contracts are excluded from Topic 606. Accounts receivable balances are included in “Accounts receivable” in the merger date (See Note 2). Condensed Consolidated Balance Sheets.
The Company providesdoes not have any significant contract asset balances, and as such, contract balances are not presented at the net amount at a dual presentation of its net loss per common sharecontract 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 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.
Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock and restricted stock units. The dilutive effect of stock options and restricted stock units is determined using the treasury stock method. The dilutive effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class method, assuming a reallocation of undistributed earnings to common stockholders after considering the dilutive effect of potential common shares other than non-vested shares of restricted stock.
8
The following table presents information necessary to calculate net loss per sharecontract liabilities are payments received from customers for the three and nine months ended September 30, 2017 and 2016 as well as potentially dilutive securities excluded from the weighted average numberinitial mobilization of diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per share amounts):
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
BASIC EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributed to common stockholders | $ | (33,769 | ) |
| $ | (84,143 | ) |
| $ | (189,492 | ) |
| $ | (240,512 | ) |
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock |
| 211,875 |
|
|
| 146,326 |
|
|
| 191,237 |
|
|
| 146,014 |
|
Basic net loss per common share | $ | (0.16 | ) |
| $ | (0.58 | ) |
| $ | (0.99 | ) |
| $ | (1.65 | ) |
DILUTED EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributed to common stockholders | $ | (33,769 | ) |
| $ | (84,143 | ) |
| $ | (189,492 | ) |
| $ | (240,512 | ) |
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock |
| 211,875 |
|
|
| 146,326 |
|
|
| 191,237 |
|
|
| 146,014 |
|
Add dilutive effect of potential common shares |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Weighted average number of diluted common shares outstanding |
| 211,875 |
|
|
| 146,326 |
|
|
| 191,237 |
|
|
| 146,014 |
|
Diluted net loss per common share | $ | (0.16 | ) |
| $ | (0.58 | ) |
| $ | (0.99 | ) |
| $ | (1.65 | ) |
Potentially dilutive securities excluded as anti-dilutive |
| 9,973 |
|
|
| 9,141 |
|
|
| 9,973 |
|
|
| 9,141 |
|
2. Acquisitions
Seventy Seven Energy Inc. (“SSE”)
On April 20, 2017, pursuantnewly constructed or upgraded rigs that were moved on location 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® class rigs. Additionally, through the SSE merger, the Company 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 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 isinitial well site. These mobilization payments are allocated to the tangibleoverall performance obligation and intangible assets acquiredamortized over the initial term of the contract. During the six months ended June 30, 2019 and 2018, approximately $0.8 million and $0.8 million, respectively, was amortized and recorded in drilling revenue.
Contract liability balances for customer prepayments were $4.0 million and $3.0 million as of June 30, 2019 and December 31, 2018, respectively. Contract liability balances for deferred mobilization payments relating to newly constructed or upgraded rigs were $3.9 million and $4.6 million as of June 30, 2019 and December 31, 2018, respectively. Contract liability balances for customer prepayments are included in “Accounts payable” and contract liability balances for deferred mobilization payments are included in “Accrued liabilities” in the liabilities assumedCondensed Consolidated Balance Sheets.
Contract Costs
Costs incurred for newly constructed or rig upgrades based on their estimated fair values as of the acquisition date,a contract 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 acquireda customer are considered capital improvements 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 subjectare capitalized to revision as additional information about the fair value of assetsdrilling equipment 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 materially 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 purchase pricedepreciated over the estimated fair valueuseful life of the identifiable net assets acquired recorded as goodwill (in thousands):
Identifiable assets acquired |
|
|
|
Cash and cash equivalents | $ | 37,806 |
|
Accounts receivable |
| 149,598 |
|
Inventory |
| 8,036 |
|
Other current assets |
| 19,250 |
|
Property and equipment |
| 984,430 |
|
Other long-term assets |
| 14,546 |
|
Intangible assets |
| 22,500 |
|
Total identifiable assets acquired |
| 1,236,166 |
|
Liabilities assumed |
|
|
|
Accounts payable and accrued liabilities |
| 130,100 |
|
Deferred income taxes |
| 31,402 |
|
Other long-term liabilities |
| 1,734 |
|
Total liabilities assumed |
| 163,236 |
|
Net identifiable assets acquired |
| 1,072,930 |
|
Goodwill |
| 438,466 |
|
Total net assets acquired | $ | 1,511,396 |
|
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. See Note 7 for a breakdown of goodwill acquired by 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 |
|
|
|
|
|
Favorable drilling contracts | $ | 22,500 |
|
| 1 |
10
The results of SSE’s operations since the merger date are included in our consolidated statement of operations. The following pro forma condensed combined financial information was derived from the historical financial statements of the Company and SSE and gives effect to the merger as if it 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 SSE, (iii) 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 merger. Additionally, the pro forma loss for the three months ended September 30, 2017 was adjusted to exclude the Company’s merger and integration-related costs of $9.4 million. The pro forma loss for the nine months ended September 30, 2017 was adjusted to exclude the Company’s merger and integration-related costs of $65.8 million and SSE’s merger-related costs of $36.7 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the SSE merger or any estimated costs that have been or will be incurred by the Company to integrate the SSE operations. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the SSE merger 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 |
|
| Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues | $ | 684,989 |
|
| $ | 326,227 |
|
| $ | 1,811,903 |
|
| $ | 1,082,554 |
|
Net loss |
| (27,627 | ) |
|
| (117,185 | ) |
|
| (189,098 | ) |
|
| (346,481 | ) |
Loss per share |
| (0.13 | ) |
|
| (0.56 | ) |
|
| (0.89 | ) |
|
| (1.65 | ) |
Multi-Shot, LLC (“MS Directional”)
On October 11, 2017, the Company acquired all of the issued and outstanding limited liability company interests of Multi-Shot, LLC (“MS Directional”). The aggregate consideration paid by the Company to the sellers consisted of $75 million in cash and 8,798,391 shares of the Company’s common stock. The purchase price is 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 $262 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.
The Company’s consolidated results of operations will include the results of the acquired MS Directional business beginning with the closing date of the acquisition of October 11, 2017. Due to the timing of the closing of the acquisition, the Company has not completed the detailed valuation work necessary to determine the required estimates of the fair value of the acquired assets and liabilities assumed and the related allocation of purchase price. MS Directional had total assets of approximately $104 million as of December 31, 2016, consisting of $21.4 million of accounts receivable, $23.9 million of inventory, $53.8 million of property and equipment and $4.9 million of other assets. The Company’s preliminary allocation of purchase price to the assets acquired will be included in future SEC filings of the Company.
As this transaction closed subsequent to the end of the third quarter of 2017, the condensed consolidated financial statements and accompanying notes do not reflect any amounts relating to MS Directional.asset.
3. Stock-based Compensation4. Leases
ASC Topic 842 Leases
On January 1, 2019, the Company adopted the new lease guidance under Topic 842, Leases, using the modified retrospective approach to each lease that existed at the date of initial application as well as leases entered into after that date. The Company has elected to report all leases at the beginning of the period of adoption and not restate its comparative periods. This standard does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained.
The Company uses share-based paymentshas entered into operating leases for operating locations, corporate offices and certain operating equipment. These leases have remaining lease terms of 6 months to compensate employees and non-employee directors.9 years as of June 30, 2019. Currently, the Company does not have any finance leases. The Company recognizeshas elected the costshort-term lease recognition practical expedient whereby right of share-baseduse assets and lease liabilities are not recognized for leasing arrangements with an initial term of one year or less.
Topic 842 requires that lessees and lessors discount lease payments underat the fair-value-based method. Share-based awards include equity instrumentslease commencement date using the rate implicit in the form of stock options, restricted stocklease, if available, 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.
11
The Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan (the “2014 Plan”) was originally approved by the Company’s stockholders effective as of April 17, 2014. On June 29, 2017, the Company’s stockholders approved the amendment and restatement of the 2014 Plan (the “Amended and Restated Plan”) to increase the number of shares available for future issuance under the plan to 10,049,156 shares. The aggregate number of shares of Common Stock authorized for grant under the Amended and Restated Plan is 18.9 million, which includes the 9.1 million shares previously authorized under the 2014 Plan.
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 or nine months ended September 30, 2017. Weighted-average assumptions used to estimate the grant date fair values for stock options granted for the three and nine month periods ended September 30, 2016 follow:
| Three Months Ended |
|
| Nine Months Ended |
| ||
| September 30, |
|
| September 30, |
| ||
| 2016 |
|
| 2016 |
| ||
Volatility |
| 34.87 | % |
|
| 35.11 | % |
Expected term (in years) |
| 5.00 |
|
|
| 5.00 |
|
Dividend yield |
| 0.42 | % |
|
| 2.05 | % |
Risk-free interest rate |
| 1.20 | % |
|
| 1.40 | % |
Stock option activity from January 1, 2017 to September 30, 2017 follows:
|
|
|
|
| Weighted |
| |
|
|
|
|
| Average |
| |
| Underlying |
|
| Exercise Price |
| ||
| Shares |
|
| Per Share |
| ||
Outstanding at January 1, 2017 |
| 6,687,150 |
|
| $ | 20.68 |
|
Exercised |
| (10,000 | ) |
| $ | 22.29 |
|
Expired |
| (600,000 | ) |
| $ | 24.17 |
|
Outstanding at September 30, 2017 |
| 6,077,150 |
|
| $ | 20.34 |
|
Exercisable at September 30, 2017 |
| 5,421,310 |
|
| $ | 20.50 |
|
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-forfeitable dividends are paid on non-vested shares of restricted stock.lessee’s incremental borrowing rate. The Company uses the straight-line methodimplicit rate when readily determinable. If the implicit rate is not readily determinable, the Company uses its incremental borrowing rate based on the information available at the commencement date in the determination of the present value of future lease payments.
Practical Expedients Adopted with Topic 842
The Company has elected to recognize periodic compensation cost overadopt the vesting period.
Restricted stock activity fromfollowing practical expedients upon the transition date to Topic 842 on January 1, 20172019:
Transitional practical expedients package: An entity may elect to September 30, 2017 follows:
|
|
|
|
| Weighted |
| |
|
|
|
|
| Average Grant |
| |
|
|
|
|
| Date Fair Value |
| |
| Shares |
|
| Per Share |
| ||
Non-vested restricted stock outstanding at January 1, 2017 |
| 1,427,455 |
|
| $ | 22.26 |
|
Granted |
| 890,904 |
|
| $ | 21.78 |
|
Vested |
| (724,626 | ) |
| $ | 23.62 |
|
Forfeited |
| (16,003 | ) |
| $ | 22.80 |
|
Non-vested restricted stock outstanding at September 30, 2017 |
| 1,577,730 |
|
| $ | 21.36 |
|
Restricted Stock Units — Forapply the listed practical expedients as a package to 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. Non-forfeitable cash dividend equivalents are paid on certain non-vested restricted stock units.leases that commenced before the effective date. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period.practical expedients are:
12
Restricted stock unit activity from January 1, 2017 to September 30, 2017 follows:
|
|
|
|
| Weighted |
| |
|
|
|
|
| Average Grant |
| |
|
|
|
|
| Date Fair Value |
| |
| Shares |
|
| Per Share |
| ||
Non-vested restricted stock units outstanding at January 1, 2017 |
| 191,655 |
|
| $ | 19.85 |
|
Granted |
| 1,090,292 |
|
| $ | 19.75 |
|
Assumed (1) |
| 505,551 |
|
| $ | 22.45 |
|
Vested |
| (549,451 | ) |
| $ | 22.24 |
|
Forfeited |
| (38,374 | ) |
| $ | 21.61 |
|
Non-vested restricted stock units outstanding at September 30, 2017 |
| 1,199,673 |
|
| $ | 19.71 |
|
|
|
|
b) | The entity need not reassess the lease classification for expired or existing contracts; | |
c) | The entity need not reassess initial direct costs for any existing leases. |
• | Use of portfolio approach: An entity can apply this guidance to a portfolio of leases with similar characteristics if the entity reasonably expects that the application of the leases model to the portfolio would not differ materially from the application of the leases model to the individual leases in that portfolio. This approach can also be applied to other aspects of the leases guidance for which lessees/lessors need to make judgments and estimates, such as determining the discount rate and determining and reassessing the lease term. | |
• | Lease and non-lease components: As a practical expedient, lease and non-lease components may be combined where the revenue recognition pattern is the same and where the lease component, when accounted for separately, would be considered an operating lease. The Company’s contract drilling, pressure pumping and directional drilling contracts contain a lease component related to the underlying equipment utilized, in addition to the service component provided by the Company’s crews and expertise to operate the related equipment. The Company has concluded that the non-lease service of operating its equipment and providing expertise in the services provided to our customers is predominant in the Company’s drilling, pressure pumping and directional drilling contracts. With the election of this practical expedient, the Company will continue to present a single performance obligation for these contracts under the |
Lease expense consisted of the following for the three and six months ended June 30, 2019 (in thousands):
|
|
|
|
|
|
|
|
| Three Months Ended |
|
| Six Months Ended |
| ||
| June 30, 2019 |
|
| June 30, 2019 |
| ||
Operating lease cost | $ | 2,755 |
|
| $ | 5,794 |
|
Short-term lease expense (1) |
| 111 |
|
|
| 387 |
|
Total lease expense | $ | 2,866 |
|
| $ | 6,181 |
|
(1) | Short-term lease expense represents expense related to leases with |
Supplemental cash flow information related to leases for the six months ended June 30, 2019 is as follows (in thousands):
| Six Months Ended |
| |
| June 30, 2019 |
| |
Cash paid for amounts included in the measurement of lease liabilities: |
|
|
|
Operating cash flows from operating leases | $ | 5,165 |
|
|
|
|
|
Right of use assets obtained in exchange for lease obligations: |
|
|
|
Operating leases | $ | 627 |
|
Supplemental balance sheet information related to leases as of June 30, 2019 is as follows:
June 30, 2019 | |||
Weighted Average Remaining Lease Term: | |||
Operating leases | 4.9 years | ||
Weighted Average Discount Rate: | |||
Operating leases | 4.5 | % |
Performance Unit Awards. The Company has granted share-settled performance unit awards to certain executive officers (the “Performance Units”)Maturities of operating lease liabilities as of June 30, 2019 are as follows (in thousands):
Year ending December 31, |
|
|
|
2019 (excluding the six months ended June 30, 2019) | $ | 5,268 |
|
2020 |
| 9,195 |
|
2021 |
| 6,668 |
|
2022 |
| 4,625 |
|
2023 |
| 2,663 |
|
Thereafter |
| 6,552 |
|
Total lease payments |
| 34,971 |
|
Less imputed interest |
| (3,639 | ) |
Total | $ | 31,332 |
|
Maturities of operating lease liabilities as of December 31, 2018, as previously disclosed in the Company’s Annual Report on an annual basis since 2010. The Performance Units provideForm 10-K 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 thefiscal 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 on a pro-rata basis.
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 MarchDecember 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.
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 performance and does not have an absolute performance requirement.
The total target number of shares with respect to the Performance Units for the awards 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 belowfollows (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 September 30, 2017 | $ | 482 |
|
| $ | 321 |
|
| $ | 338 |
|
| NA |
|
| NA |
| ||
Three months ended September 30, 2016 | NA |
|
| $ | 321 |
|
| $ | 338 |
|
| $ | 449 |
|
| NA |
| ||
Nine months ended September 30, 2017 | $ | 803 |
|
| $ | 963 |
|
| $ | 1,013 |
|
| $ | 449 |
|
| NA |
| |
Nine months ended September 30, 2016 | NA |
|
| $ | 642 |
|
| $ | 1,013 |
|
| $ | 1,347 |
|
| $ | 464 |
|
Year ending December 31, |
|
|
|
2019 | $ | 11,408 |
|
2020 |
| 9,069 |
|
2021 |
| 6,543 |
|
2022 |
| 4,625 |
|
2023 |
| 2,663 |
|
Thereafter |
| 6,552 |
|
Total | $ | 40,860 |
|
4.5. Inventory
Inventory consisted of the following at SeptemberJune 30, 20172019 and December 31, 20162018 (in thousands):
| September 30, |
|
| December 31, |
|
|
|
|
|
|
|
| ||
| 2017 |
|
| 2016 |
| June 30, 2019 |
|
| December 31, 2018 |
| ||||
Finished goods | $ | 1,332 |
|
| $ | — |
| $ | 7 |
|
| $ | 347 |
|
Work-in-process |
| 3,910 |
|
|
| 1,803 |
|
| 8,194 |
|
|
| 6,375 |
|
Raw materials and supplies |
| 35,430 |
|
|
| 18,388 |
|
| 60,410 |
|
|
| 58,857 |
|
Inventory | $ | 40,672 |
|
| $ | 20,191 |
| $ | 68,611 |
|
| $ | 65,579 |
|
5.6. Property and Equipment
Property and equipment consisted of the following at SeptemberJune 30, 20172019 and December 31, 20162018 (in thousands):
| September 30, |
|
| December 31, |
|
|
|
|
|
|
|
| ||
| 2017 |
|
| 2016 |
| June 30, 2019 |
|
| December 31, 2018 |
| ||||
Equipment | $ | 7,882,765 |
|
| $ | 6,809,129 |
| $ | 8,321,611 |
|
| $ | 8,370,933 |
|
Oil and natural gas properties |
| 209,912 |
|
|
| 201,568 |
|
| 220,634 |
|
|
| 219,855 |
|
Buildings |
| 186,452 |
|
|
| 97,029 |
|
| 187,958 |
|
|
| 186,736 |
|
Land |
| 26,630 |
|
|
| 22,270 |
|
| 26,618 |
|
|
| 26,144 |
|
Total property and equipment |
| 8,305,759 |
|
|
| 7,129,996 |
|
| 8,756,821 |
|
|
| 8,803,668 |
|
Less accumulated depreciation, depletion and impairment |
| (4,107,474 | ) |
|
| (3,721,033 | ) |
| (4,987,563 | ) |
|
| (4,801,119 | ) |
Property and equipment, net | $ | 4,198,285 |
|
| $ | 3,408,963 |
| $ | 3,769,258 |
|
| $ | 4,002,549 |
|
On a periodic basis, theThe 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 the second quarter of 2017, the Company recorded an impairment charge of $29.0 million for the write-down of drilling equipment with no continuing utility as a result of the upgrade of certain rigs to super-spec capability.
14
In addition, the Company evaluates the recoverability ofreviews its long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that theirthe carrying amounts of certain assets may not be recoverable (a “triggering event”recovered over their estimated remaining useful lives (“triggering events”). BasedIn connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The Company estimates future cash flows over the life of the respective assets or asset groupings in its assessment of impairment. These estimates of cash flows are based on recent commodity prices,historical cyclical trends in the industry as well as the Company’s expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Any provision for impairment is measured at fair value.
The Company concluded that no triggering events occurred during the six months ended June 30, 2019 with respect to its asset groups based on the Company’s results of operations for the three months and nine month periodssix months ended SeptemberJune 30, 2017 and2019, management’s expectations of operating results in future periods and the Company concluded that no triggering event occurred duringprevailing commodity prices at the nine months ended September 30, 2017 with respect to its contract drilling segment, its pressure pumping 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 both segments and its other operations will remain relatively stable in response to relatively stable 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 $1.3 million in the third quarter of 2017 and $3.5 million for the nine months ended September 30, 2017 and is included in depreciation, depletion, amortization and impairment in the condensed consolidated statements of operations.time.
6. Business Segments
At September 30, 2017, the Company’s revenues, loss before income taxes and identifiable assets were primarily attributable to two business segments: (i) contract drilling of oil and natural gas wells and (ii) pressure pumping 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.
15
The following tables summarize selected financial information relating to the Company’s business segments (in thousands):
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling | $ | 301,954 |
|
| $ | 123,863 |
|
| $ | 731,496 |
|
| $ | 407,855 |
|
Pressure pumping |
| 362,441 |
|
|
| 78,165 |
|
|
| 793,659 |
|
|
| 248,428 |
|
Other operations (a) |
| 22,832 |
|
|
| 4,284 |
|
|
| 48,092 |
|
|
| 12,973 |
|
Elimination of intercompany revenues (b) |
| (2,238 | ) |
|
| (179 | ) |
|
| (3,897 | ) |
|
| (277 | ) |
Total revenues | $ | 684,989 |
|
| $ | 206,133 |
|
| $ | 1,569,350 |
|
| $ | 668,979 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling | $ | (20,397 | ) |
| $ | (67,786 | ) |
| $ | (155,465 | ) |
| $ | (173,331 | ) |
Pressure pumping |
| 16,841 |
|
|
| (46,569 | ) |
|
| (1,414 | ) |
|
| (136,553 | ) |
Other operations |
| (6,516 | ) |
|
| 228 |
|
|
| (13,030 | ) |
|
| (2,263 | ) |
Corporate |
| (31,735 | ) |
|
| (13,400 | ) |
|
| (119,483 | ) |
|
| (41,138 | ) |
Other operating income, net (c) |
| 3,791 |
|
|
| 4,118 |
|
|
| 18,501 |
|
|
| 10,285 |
|
Interest income |
| 101 |
|
|
| 63 |
|
|
| 1,149 |
|
|
| 273 |
|
Interest expense |
| (9,584 | ) |
|
| (10,244 | ) |
|
| (26,929 | ) |
|
| (31,722 | ) |
Other |
| 78 |
|
|
| 19 |
|
|
| 226 |
|
|
| 52 |
|
Loss before income taxes | $ | (47,421 | ) |
| $ | (133,571 | ) |
| $ | (296,445 | ) |
| $ | (374,397 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and impairment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling | $ | 133,603 |
|
| $ | 115,652 |
|
| $ | 405,576 |
|
| $ | 357,153 |
|
Pressure pumping |
| 51,274 |
|
|
| 44,587 |
|
|
| 141,329 |
|
|
| 141,557 |
|
Other operations |
| 9,534 |
|
|
| 1,856 |
|
|
| 19,826 |
|
|
| 8,393 |
|
Corporate |
| 2,231 |
|
|
| 1,369 |
|
|
| 5,456 |
|
|
| 4,106 |
|
Total depreciation, depletion, amortization and impairment | $ | 196,642 |
|
| $ | 163,464 |
|
| $ | 572,187 |
|
| $ | 511,209 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling | $ | 106,879 |
|
| $ | 17,551 |
|
| $ | 222,426 |
|
| $ | 46,001 |
|
Pressure pumping |
| 27,230 |
|
|
| 8,330 |
|
|
| 85,423 |
|
|
| 27,662 |
|
Other operations |
| 8,647 |
|
|
| 2,401 |
|
|
| 21,016 |
|
|
| 5,621 |
|
Corporate |
| 305 |
|
|
| 395 |
|
|
| 986 |
|
|
| 1,227 |
|
Total capital expenditures | $ | 143,061 |
|
| $ | 28,677 |
|
| $ | 329,851 |
|
| $ | 80,511 |
|
| September 30, |
|
| December 31, |
| ||
| 2017 |
|
| 2016 |
| ||
Identifiable assets: |
|
|
|
|
|
|
|
Contract drilling | $ | 3,950,748 |
|
| $ | 3,032,819 |
|
Pressure pumping |
| 1,227,384 |
|
|
| 653,630 |
|
Other operations |
| 166,900 |
|
|
| 48,885 |
|
Corporate (d) |
| 127,943 |
|
|
| 36,957 |
|
Total assets | $ | 5,472,975 |
|
| $ | 3,772,291 |
|
|
|
|
|
|
|
|
|
7. Goodwill and Intangible Assets
Goodwill — Goodwill by operating segment as of SeptemberJune 30, 20172019 and changes for the ninesix months then ended are as follows (in thousands):
| Contract |
|
| Pressure |
|
|
|
|
| Contract |
|
| Other |
|
|
|
|
| ||||
| Drilling |
|
| Pumping |
|
| Total |
| Drilling |
|
| Operations |
|
| Total |
| ||||||
Balance at beginning of period | $ | 86,234 |
|
| $ | — |
|
| $ | 86,234 |
| $ | 395,060 |
|
|
| 15,696 |
|
| $ | 410,756 |
|
Goodwill acquired |
| 300,819 |
|
|
| 137,647 |
|
|
| 438,466 |
| |||||||||||
Changes to goodwill |
| — |
|
|
| 2,104 |
|
|
| 2,104 |
| |||||||||||
Balance at end of period | $ | 387,053 |
|
| $ | 137,647 |
|
| $ | 524,700 |
| $ | 395,060 |
|
| $ | 17,800 |
|
| $ | 412,860 |
|
The goodwill reflected above in Other Operations has increased primarily as a result of a measurement period adjustment related to accrued liabilities, which resulted in a $2.1 million increase from the original purchase price allocation assessed with the Current Power acquisition. There were no accumulated impairment losses related to goodwill in the contract drilling segment or other operations as of SeptemberJune 30, 20172019 or December 31, 2016.2018.
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 its carrying value after considering qualitative, market and other 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 goodwill impairment in lieu of performing the qualitative assessment. If the 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 SeptemberJune 30, 20172019 and December 31, 20162018 (in thousands):
| September 30, 2017 |
|
| December 31, 2016 |
| June 30, 2019 |
|
| December 31, 2018 |
| ||||||||||||||||||||||||||||||||||||
| Gross |
|
|
|
|
|
| Net |
|
| Gross |
|
|
|
|
|
| Net |
| Gross |
|
|
|
|
|
| Net |
|
| Gross |
|
|
|
|
|
| Net |
| ||||||||
| Carrying |
|
| Accumulated |
|
| Carrying |
|
| Carrying |
|
| Accumulated |
|
| Carrying |
| Carrying |
|
| Accumulated |
|
| Carrying |
|
| Carrying |
|
| Accumulated |
|
| Carrying |
| ||||||||||||
| Amount |
|
| Amortization |
|
| Amount |
|
| Amount |
|
| Amortization |
|
| Amount |
| Amount |
|
| Amortization |
|
| Amount |
|
| Amount |
|
| Amortization |
|
| Amount |
| ||||||||||||
Customer relationships | $ | 25,500 |
|
| $ | (25,500 | ) |
| $ | — |
|
| $ | 25,500 |
|
| $ | (22,768 | ) |
| $ | 2,732 |
| $ | 28,000 |
|
| $ | (15,214 | ) |
|
| 12,786 |
|
| $ | 28,000 |
|
| $ | (10,719 | ) |
| $ | 17,281 |
|
Developed technology |
| 55,772 |
|
|
| (9,321 | ) |
|
| 46,451 |
|
|
| 55,772 |
|
|
| (6,533 | ) |
|
| 49,239 |
| |||||||||||||||||||||||
Favorable drilling contracts |
| 22,500 |
|
|
| (13,518 | ) |
|
| 8,982 |
|
|
| — |
|
|
| — |
|
|
| — |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 22,500 |
|
|
| (22,500 | ) |
|
| — |
|
Internal use software |
| 482 |
|
|
| (166 | ) |
|
| 316 |
|
|
| 482 |
|
|
| (118 | ) |
|
| 364 |
| |||||||||||||||||||||||
| $ | 48,000 |
|
| $ | (39,018 | ) |
| $ | 8,982 |
|
| $ | 25,500 |
|
| $ | (22,768 | ) |
| $ | 2,732 |
| $ | 84,254 |
|
| $ | (24,701 | ) |
| $ | 59,553 |
|
| $ | 106,754 |
|
| $ | (39,870 | ) |
| $ | 66,884 |
|
Amortization expense on intangible assets of approximately $6.6$3.7 million and $911,000$4.9 million was recorded in the three months ended SeptemberJune 30, 20172019 and 2016, respectively, and amortization2018, respectively. Amortization expense on intangible assets of approximately $16.3$7.3 million and $2.7$10.3 million was recorded in the ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, respectively.
8. Accrued ExpensesLiabilities
Accrued expensesliabilities consisted of the following at SeptemberJune 30, 20172019 and December 31, 20162018 (in thousands):
| September 30, |
|
| December 31, |
|
|
|
|
|
|
|
| ||
| 2017 |
|
| 2016 |
| June 30, 2019 |
|
| December 31, 2018 |
| ||||
Salaries, wages, payroll taxes and benefits | $ | 56,777 |
|
| $ | 21,138 |
| $ | 43,832 |
|
| $ | 58,160 |
|
Workers' compensation liability |
| 82,509 |
|
|
| 67,775 |
|
| 74,604 |
|
|
| 83,772 |
|
Property, sales, use and other taxes |
| 29,382 |
|
|
| 6,766 |
|
| 34,149 |
|
|
| 25,318 |
|
Insurance, other than workers' compensation |
| 10,881 |
|
|
| 9,566 |
|
| 8,844 |
|
|
| 9,531 |
|
Accrued interest payable |
| 14,091 |
|
|
| 6,740 |
|
| 16,471 |
|
|
| 15,774 |
|
Accrued merger and integration |
| 20,538 |
|
|
| — |
| |||||||
Other |
| 31,648 |
|
|
| 27,163 |
|
| 40,732 |
|
|
| 43,391 |
|
Total | $ | 245,826 |
|
| $ | 139,148 |
| $ | 218,632 |
|
| $ | 235,946 |
|
17
20122018 Credit Agreement — On SeptemberMarch 27, 2012,2018, the Company entered into a Credit Agreementan amended and restated credit agreement (the “Base Credit“Credit Agreement”) withamong the Company, as borrower, Wells Fargo Bank, N.A.,National Association, as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders and letter of credit issuers party thereto.thereto, The BaseBank 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 (as amended, the “Credit Agreement”) is a committed senior unsecured revolving credit facility that includes a revolving credit facility.
On July 8, 2016, the Company entered into Amendment No. 2permits aggregate borrowings of up to Credit Agreement (“Amendment No. 2”), which amended the Base Credit Agreement to, among other things, make borrowing under the revolving credit facility subject to a borrowing base calculated by reference to the Company’s and certain of its subsidiaries’ eligible equipment, inventory, accounts receivable and unencumbered cash as described in Amendment No. 2. The revolving credit facility contains$600 million, including a letter of credit facility that, at any time outstanding, is limited to $50$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, in each case outstanding at any time.not to exceed total commitments of $900 million. The original maturity date under the Base Credit Agreement was September 27, 2017 for the revolving facility; however, Amendment No. 2 extended the maturity date of $357.9 million in revolving credit commitments of certain lenders to March 27, 2019.2023. On January 17, 2017,March 26, 2019, the Company entered into Amendment No. 31 to Amended and Restated Credit Agreement (the “Amendment”), which amended the Credit Agreement by restatingto, among other things, extend the definition of Consolidated EBITDAmaturity date under the Credit Agreement from March 27, 2023 to provide forMarch 27, 2024. The Company has the add-back of transaction expenses related to the SSE merger. On January 24, 2017, the Company entered into an agreement with certain lenders under its revolving credit facility to increase the aggregate commitments under its revolving credit facility to approximately $595.8 million,option, subject to the satisfaction of certain conditions. The aggregate commitment increase became effective on April 20, 2017 upon the consummationconditions, to exercise two one-year extensions of the SSE merger and the repayment and termination of the SSE credit facility. On April 20, 2017, the Company entered into Amendment No. 4 to Credit Agreement which permitted outstanding letters of credit under the SSE credit facility to be deemed to be incurred under the Company’s credit facility and increased the amount of the accordion feature of the Company’s revolving credit facility to permit aggregate commitments to be increased to an amount not to exceed $700 million (subject to satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). On April 20, 2017, the Company also entered into an additional commitment increase agreement with certain of its lenders pursuant to which total commitments available under the Company’s revolving credit facility (after giving effect to both commitment increases) increased to $632 million through September 2017 and to $490 million through March 2019. On October 27, 2017, the Company entered into an additional commitment increase agreement with certain of its lenders pursuant to which total commitments available under the Company’s revolving credit facility increased to $500 million through March 2019.maturity date.
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. Until September 27, 2017, theThe applicable margin on LIBOR rate loans variedvaries from 2.75%1.00% to 3.25%2.00% and the applicable margin on base rate loans variedvaries from 1.75%0.00% to 2.25%1.00%, in each case determined based upon the Company’s debt to capitalization ratio. Based on the Company’s debt to capitalization ratio at March 31, 2017, the applicable margin on LIBOR loans was 2.75% and the applicable margin on base rate loans was 1.75% as of July 1, 2017. Beginning September 27, 2017, the applicable margin on LIBOR rate loans varies from 3.25% to 3.75% and the applicable margin on base rate loans varies from 2.25% to 2.75%, in each case determined based on the Company’s excess availability under the revolving credit facility. As of September 30, 2017, the applicable margin on LIBOR rate loans was 3.25% and the applicable margin on base rate loans was 2.25%.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 forvaries from 0.10% to 0.30% based on the unused portion of the revolvingCompany’s credit facility is 0.50%.rating.
Each domestic subsidiaryNo subsidiaries of the Company unconditionally guarantees all existing and future indebtedness and liabilities of the other guarantors and the Company arisingare currently required to be a guarantor under the Credit Agreement, other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no material assets other than equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c)Agreement. However, if any subsidiary having total assetsguarantees or incurs debt in excess of less than $1 million. Such guarantees also cover obligationsthe 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 any each subsidiary of the Company arising under any interest rate swap contract with any person while such personto incur debt and grant liens. If the Company’s credit rating is below investment grade, the Company will become subject to a lender or an affiliate ofrestricted payment covenant, which would require the Company to have a lender underPro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement.
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 compliance with two financial covenants. The Company must not permit itsthat the Company’s total debt to capitalization ratio, toexpressed as a percentage, not exceed 40%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 last dayend 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 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. The Company was in compliance with these covenants at September 30, 2017.
18
The Credit Agreement limits the Company’s ability to make investments in foreign subsidiaries or joint ventures such that, if the book value of all such investments since September 27, 2012 is above 20% of the total consolidated book value of the assets of the Company and its subsidiaries on a pro forma basis, the Company will not be able to make such investment. The Credit Agreement also restricts the Company’s ability to pay dividends and make equity repurchases, subject to certain exceptions, including an exception allowing such restricted payments if, before and immediately after giving effect to such restricted payment, the Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) is at least 1.50 to 1.00. In addition, the Credit Agreement requires that, if the consolidated cash balance of the Company and its subsidiaries, subject to certain exclusions, is more than $100 million at the end of the day on which a borrowing is made, the Company can only use the proceeds from such borrowing to fund acquisitions, capital expenditures and the repurchase of indebtedness, and if such proceeds are not used in such manner within three business days, the Company must repay such unused proceeds on the fourth business day following such borrowings.
The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants.
Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require the Company to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy of the Company, such acceleration is automatic), and (iii) require the Company to cash collateralize any outstanding letters of credit.
As of SeptemberJune 30, 2017,2019, the Company had $144 millionno amounts outstanding under the revolving credit facility. The Company had $81,000 in letters of credit outstanding under the revolving credit facility at a weighted average interest rate of 4.83%. The Company had $4.6 million in letters of credit outstanding at SeptemberJune 30, 20172019 and, as a result, had available borrowing capacity of $342approximately $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 SeptemberJune 30, 2017,2019, the Company had $54.9$63.3 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.
The Series A Notes and Series B Notes are senior unsecured obligations of the Company which rank equally in right of payment with all other unsubordinated indebtedness of the Company. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of the existing domestic subsidiaries of the Company other than 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.
19
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 SeptemberJune 30, 2017.2019.
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”). 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 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 in 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 in 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.
Upon the occurrence of a change of control, as defined in the indenture, each holder of the 2028 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, 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 $710,000$336,000 and $2.0 million$354,000 for the three months ended SeptemberJune 30, 20172019 and 2016,2018, respectively and $2.0$0.7 million and $3.5$1.3 million for the ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, respectively. Amortization of debt issuance costs for the three and ninesix months ended SeptemberJune 30, 20162018 includes $1.4 million$317,000 of debt issuance costs related to commitments by lenders under the early termination of term loan agreements.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 SeptemberJune 30, 20172019 (in thousands):
Year ending December 31, |
|
|
|
|
|
|
2017 | $ | — |
| |||
2018 |
| — |
| |||
2019 |
| 144,000 |
| $ | — |
|
2020 |
| 300,000 |
|
| 300,000 |
|
2021 |
| — |
|
| — |
|
2022 |
| 300,000 |
| |||
2023 |
| — |
| |||
Thereafter |
| 300,000 |
|
| 525,000 |
|
Total | $ | 744,000 |
| $ | 1,125,000 |
|
10. Commitments and Contingencies
As of SeptemberJune 30, 2017,2019, the Company maintained letters of credit in the aggregate amount of $59.5$63.4 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 SeptemberJune 30, 2017,2019, no amounts had been drawn under the letters of credit.
As of SeptemberJune 30, 2017,2019, the Company had commitments to purchase major equipment and make investments totaling approximately $191$72.8 million for its drilling, pressure pumping, directional drilling and oilfield rental toolsrentals businesses.
The Company’s pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. TheseThe agreements expire in 2017, 2018, 2021 and 2041.years 2019 through 2023. As of SeptemberJune 30, 2017,2019, the remaining obligation under these agreements was approximately $86.9$42.2 million, of which approximately $345,000 and $9.5$14.9 million relates to purchases required during the remainder of 2017 and 2018, respectively.2019. In the event the required minimum quantities are not purchased during certain periods,any contract year, the Company could be required to make a liquidated damages payment to the respective vendor for any shortfall. In 2017, the Company entered into a capacity reservation agreement that required a cash deposit to increase the Company’s access to finer grades of sand for its pressure pumping business. As market prices for sand have substantially decreased since 2017, the Company has purchased lower cost sand outside of this capacity reservation contract and recorded a charge of $12.7 million in the quarter ended June 30, 2019 to revalue the deposit to its expected realizable value.
20On 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 and one of the Company’s employees who was injured in the accident. The lawsuits have been consolidated for discovery purposes under Cause No. CJ-2018-60 (the “Litigation”). The Company has finalized settlement agreements with each of the plaintiffs who brought wrongful death lawsuits, and the Company has been dismissed from those lawsuits. The remaining lawsuit by the Company’s surviving employee alleges various causes of action against the Company including negligence, negligence per se, gross negligence and intentional conduct, and the plaintiff seeks an unspecified amount of damages, including punitive or exemplary damages, costs, interest, and other relief. The Company disputes the plaintiff’s allegations and intends to continue 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 the Litigation. 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, cash flows or results of operations or cash flows..
11. Stockholders’ Equity
Stock Offering – On January 27, 2017, the Company completed an offering of 18.2 million shares of its common stock and raised net proceeds of $472 million. The Company used the net proceeds of the offering to repay SSE’s outstanding indebtedness of approximately $472 million.
Cash Dividends — The Company paid cash dividends during the ninesix months ended SeptemberJune 30, 20172019 and 20162018 as follows:
2017: | Per Share |
|
| Total |
| ||
|
|
|
|
| (in thousands) |
| |
Paid on March 22, 2017 | $ | 0.02 |
|
| $ | 3,326 |
|
Paid on June 22, 2017 |
| 0.02 |
|
|
| 4,269 |
|
Paid on September 21, 2017 |
| 0.02 |
|
|
| 4,271 |
|
Total cash dividends | $ | 0.06 |
|
| $ | 11,866 |
|
2019: | Per Share |
|
| Total |
| ||
|
|
|
|
| (in thousands) |
| |
Paid on March 21, 2019 | $ | 0.04 |
|
| $ | 8,499 |
|
Paid on June 20, 2019 |
| 0.04 |
|
|
| 8,344 |
|
Total cash dividends | $ | 0.08 |
|
| $ | 16,843 |
|
2016: | Per Share |
|
| Total |
| ||
|
|
|
|
| (in thousands) |
| |
Paid on March 24, 2016 | $ | 0.10 |
|
| $ | 14,712 |
|
Paid on June 23, 2016 |
| 0.02 |
|
|
| 2,953 |
|
Paid on September 22, 2016 |
| 0.02 |
|
|
| 2,953 |
|
Total cash dividends | $ | 0.14 |
|
| $ | 20,618 |
|
2018: | Per Share |
|
| Total |
| ||
|
|
|
|
| (in thousands) |
| |
Paid on March 22, 2018 | $ | 0.02 |
|
| $ | 4,443 |
|
Paid on June 21, 2018 |
| 0.04 |
|
|
| 8,832 |
|
Total cash dividends | $ | 0.06 |
|
| $ | 13,275 |
|
On October 25, 2017,July 24, 2019, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.02$0.04 per share to be paid on December 21, 2017September 19, 2019 to holders of record as of December 7, 2017.September 5, 2019. 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 purchaseauthorized purchases of up to $200 million of the Company’s common stock in open market or privately negotiated transactions. On July 25, 2018, the Company’s Board of Directors approved an increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. On February 6, 2019, the Company’s Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. 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 SeptemberJune 30, 2017,2019, the Company had remaining authorization to purchase approximately $187$100 million of the Company’s outstanding common stock under the stock buyback program. Shares of stock purchased under athe buyback program are held as treasury shares. On July 24, 2019, the Company’s Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases.
The Company acquired shares of stock from employees during the first two quarters of 2019 that are accounted for as treasury stock.
During Certain of these shares were acquired to satisfy the nine months ended September 30, 2017, the Company withheld 369,862 shares with respect toexercise price and employees’ tax withholding obligation upon the exercise of stock options. The remainder of these shares was acquired to satisfy payroll withholding obligations upon the settlement of performance unit awards and the vesting of restricted sharesstock and 7,989 shares with respect to the exercise of arestricted stock option.units. These shares were acquired at fair market valuevalue. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Plan.Long-Term Incentive Plan (the “2014 Plan”) and not pursuant to the stock buyback program.
Treasury stock acquisitions during the ninesix months ended SeptemberJune 30, 20172019 were as follows (dollars in thousands):
| Shares |
|
| Cost |
| Shares |
|
| Cost |
| ||||
Treasury shares at beginning of period |
| 43,392,617 |
|
| $ | 911,094 |
|
| 53,701,096 |
|
| $ | 1,080,448 |
|
Purchases pursuant to stock buyback program |
| 5,503 |
|
|
| 109 |
|
| 11,745,128 |
|
|
| 150,110 |
|
Acquisitions pursuant to long-term incentive plan |
| 377,851 |
|
|
| 6,923 |
|
| 912,338 |
|
|
| 12,890 |
|
Other |
| 31,013 |
|
|
| 371 |
| |||||||
Treasury shares at end of period |
| 43,775,971 |
|
| $ | 918,126 |
|
| 66,389,575 |
|
| $ | 1,243,819 |
|
The reconciliation of changes in stockholders’ equity for the periods ended June 30, 2019 and 2018, are presented as follows (in thousands):
| For the six months ended June 30, 2019 |
| |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Common Stock |
|
|
|
| Additional |
|
|
|
|
|
| Accumulated Other |
|
|
|
|
|
|
|
|
| |||||||
| Number of |
|
|
|
|
|
|
|
| Paid-in |
|
| Retained |
|
| Comprehensive |
|
| Treasury |
|
|
|
|
| |||||
| Shares |
|
| Amount |
|
|
|
| Capital |
|
| Earnings |
|
| Income (Loss) |
|
| Stock |
|
| Total |
| |||||||
Balance, December 31, 2018 |
| 267,316 |
|
| $ | 2,673 |
|
|
|
| $ | 2,827,154 |
|
| $ | 1,753,557 |
|
| $ | 2,487 |
|
| $ | (1,080,448 | ) |
| $ | 3,505,423 |
|
Net loss |
| — |
|
|
| — |
|
|
|
|
| — |
|
|
| (28,614 | ) |
|
| — |
|
|
| — |
|
|
| (28,614 | ) |
Foreign currency translation adjustment |
| — |
|
|
| — |
|
|
|
|
| — |
|
|
| — |
|
|
| 944 |
|
|
| — |
|
|
| 944 |
|
Vesting of restricted stock units |
| 38 |
|
|
| — |
|
|
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Forfeitures of restricted stock |
| (1 | ) |
|
| — |
|
|
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
| — |
|
|
| — |
|
|
|
|
| 9,338 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 9,338 |
|
Payment of cash dividends |
| — |
|
|
| — |
|
|
|
|
| — |
|
|
| (8,499 | ) |
|
| — |
|
|
| — |
|
|
| (8,499 | ) |
Dividend equivalents |
| — |
|
|
| — |
|
|
|
|
| — |
|
|
| (110 | ) |
|
| — |
|
|
| — |
|
|
| (110 | ) |
Purchase of treasury stock |
| — |
|
|
| — |
|
|
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (75,113 | ) |
|
| (75,113 | ) |
Balance, March 31, 2019 |
| 267,353 |
|
| $ | 2,673 |
|
|
|
| $ | 2,836,492 |
|
| $ | 1,716,334 |
|
| $ | 3,431 |
|
| $ | (1,155,561 | ) |
| $ | 3,403,369 |
|
Net loss |
| — |
|
|
| — |
|
|
|
|
| — |
|
|
| (49,447 | ) |
|
| — |
|
|
| — |
|
|
| (49,447 | ) |
Foreign currency translation adjustment |
| — |
|
|
| — |
|
|
|
|
| — |
|
|
| — |
|
|
| 848 |
|
|
| — |
|
|
| 848 |
|
Exercise of stock options |
| 700 |
|
|
| 7 |
|
|
|
|
| 9,212 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 9,219 |
|
Vesting of restricted stock units |
| 739 |
|
|
| 8 |
|
|
|
|
| (8 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Forfeitures of restricted stock |
| (1 | ) |
|
| — |
|
|
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
| — |
|
|
| — |
|
|
|
|
| 11,050 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 11,050 |
|
Payment of cash dividends |
| — |
|
|
| — |
|
|
|
|
| — |
|
|
| (8,344 | ) |
|
| — |
|
|
| — |
|
|
| (8,344 | ) |
Dividend equivalents |
| — |
|
|
| — |
|
|
|
|
| — |
|
|
| (126 | ) |
|
| — |
|
|
| — |
|
|
| (126 | ) |
Purchase of treasury stock |
| — |
|
|
| — |
|
|
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (88,258 | ) |
|
| (88,258 | ) |
Balance, June 30, 2019 |
| 268,791 |
|
| $ | 2,688 |
|
|
|
| $ | 2,856,746 |
|
| $ | 1,658,417 |
|
| $ | 4,279 |
|
| $ | (1,243,819 | ) |
| $ | 3,278,311 |
|
| For the six months ended June 30, 2018 |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Common Stock |
|
| Additional |
|
|
|
|
|
| Accumulated 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 |
|
Net loss |
| — |
|
|
| — |
|
|
| — |
|
|
| (10,713 | ) |
|
| — |
|
|
| — |
|
|
| (10,713 | ) |
Foreign currency translation adjustment |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1,530 | ) |
|
| — |
|
|
| (1,530 | ) |
Issuance of common stock |
| 381 |
|
|
| 4 |
|
|
| (4 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Vesting of restricted stock units |
| 10 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Forfeitures of restricted stock |
| (2 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
| — |
|
|
| — |
|
|
| 9,907 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 9,907 |
|
Payment of cash dividends |
| — |
|
|
| — |
|
|
| — |
|
|
| (8,832 | ) |
|
| — |
|
|
| — |
|
|
| (8,832 | ) |
Dividend equivalents |
| — |
|
|
| — |
|
|
| — |
|
|
| (83 | ) |
|
| — |
|
|
| — |
|
|
| (83 | ) |
Purchase of treasury stock |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (42,951 | ) |
|
| (42,951 | ) |
Balance, June 30, 2018 |
| 266,688 |
|
| $ | 2,667 |
|
| $ | 2,805,575 |
|
| $ | 2,047,379 |
|
| $ | 3,308 |
|
| $ | (978,590 | ) |
| $ | 3,880,339 |
|
On April 20, 2017, pursuant
12. Stock-based Compensation
The Company uses share-based payments to compensate employees and non-employee directors. The Company recognizes the merger agreement,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 acquired all of the issued and outstandingissues 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 SSE, in exchange for approximately 46.3 millionstock 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 during the six months ended June 30, 2019 or 2018.
Stock option activity from January 1, 2019 to June 30, 2019 follows:
|
|
|
|
| Weighted |
| |
|
|
|
|
| Average |
| |
| Underlying |
|
| Exercise Price |
| ||
| Shares |
|
| Per Share |
| ||
Outstanding at January 1, 2019 |
| 5,501,150 |
|
| $ | 19.63 |
|
Exercised |
| (700,000 | ) |
| $ | 13.17 |
|
Expired |
| — |
|
| $ | — |
|
Outstanding at June 30, 2019 |
| 4,801,150 |
|
| $ | 20.57 |
|
Exercisable at June 30, 2019 |
| 4,756,150 |
|
| $ | 20.59 |
|
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-forfeitable dividends are paid on non-vested shares of restricted stock. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period.
Restricted stock activity from January 1, 2019 to June 30, 2019 follows:
|
|
|
|
| Weighted |
| |
|
|
|
|
| Average Grant |
| |
|
|
|
|
| Date Fair Value |
| |
| Shares |
|
| Per Share |
| ||
Non-vested restricted stock outstanding at January 1, 2019 |
| 436,224 |
|
| $ | 21.41 |
|
Vested |
| (274,177 | ) |
| $ | 21.33 |
|
Forfeited |
| (1,500 | ) |
| $ | 21.71 |
|
Non-vested restricted stock outstanding at June 30, 2019 |
| 160,547 |
|
| $ | 21.55 |
|
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 that 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, 2019 to June 30, 2019 follows:
|
|
|
|
|
|
|
|
| Weighted |
| |
|
|
|
|
|
|
|
|
| Average Grant |
| |
| Time |
|
| Performance |
|
| Date Fair Value |
| |||
| Based |
|
| Based |
|
| Per Share |
| |||
Non-vested restricted stock units outstanding at January 1, 2019 |
| 2,602,608 |
|
|
| 435,315 |
|
| $ | 18.95 |
|
Granted |
| 1,505,048 |
|
|
| — |
|
| $ | 12.40 |
|
Vested |
| (591,679 | ) |
|
| — |
|
| $ | 19.39 |
|
Forfeited |
| (141,552 | ) |
|
| — |
|
| $ | 19.23 |
|
Non-vested restricted stock units outstanding at June 30, 2019 |
| 3,374,425 |
|
|
| 435,315 |
|
| $ | 16.28 |
|
Performance Unit Awards. The Company has granted share-settled performance unit awards to certain employees (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 Company.
On October 11,year of grant, except that for the Performance Units granted in 2017 the Company acquired allthree-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 issued and outstanding limited liability company interests of MS Directional for $75 million in cash and approximately 8.8 million sharesfair value of the respective Performance Units. For the Performance Units granted in May 2017 and April 2018, the recipients will receive a target number of shares if the Company’s common stock.total shareholder return during the performance period, when compared to the peer group, is at the 50th percentile. For the Performance Units granted in April 2019, the recipients will receive 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 55th 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 target percentile, or the target 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.
In April 2019, 185,000 shares were issued to settle the 2016 Performance Units. For the Performance Units granted in May 2017 and April 2018, the payout is based on relative performance and does not have an absolute performance requirement. For the Performance Units granted in April 2019, the payout shall not exceed the target number of shares if the Company’s total shareholder return is negative or zero.
The total target number of shares with respect to the Performance Units for the awards granted in 2015-2019 is set forth below:
| 2019 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||||
| Performance |
|
| Performance |
|
| Performance |
|
| Performance |
|
| Performance |
| |||||
| Unit Awards |
|
| Unit Awards |
|
| Unit Awards |
|
| Unit Awards |
|
| Unit Awards |
| |||||
Target number of shares |
| 489,800 |
|
|
| 310,700 |
|
|
| 186,198 |
|
|
| 185,000 |
|
|
| 190,600 |
|
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):
| 2019 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||||
| Performance |
|
| Performance |
|
| Performance |
|
| Performance |
|
| Performance |
| |||||
| Unit Awards |
|
| Unit Awards |
|
| Unit Awards |
|
| Unit Awards |
|
| Unit Awards |
| |||||
Fair value at date of grant | $ | 9,958 |
|
| $ | 8,004 |
|
| $ | 5,780 |
|
| $ | 3,854 |
|
| $ | 4,052 |
|
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):
| 2019 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||||
| Performance |
|
| Performance |
|
| Performance |
|
| Performance |
|
| Performance |
| |||||
| Unit Awards |
|
| Unit Awards |
|
| Unit Awards |
|
| Unit Awards |
|
| Unit Awards |
| |||||
Three months ended June 30, 2019 | $ | 830 |
|
| $ | 667 |
|
| $ | 482 |
|
| NA |
|
| NA |
| ||
Three months ended June 30, 2018 | NA |
|
| $ | 667 |
|
| $ | 482 |
|
| $ | 321 |
|
| NA |
| ||
Six months ended June 30, 2019 | $ | 830 |
|
| $ | 1,334 |
|
| $ | 963 |
|
| $ | 321 |
|
| NA |
| |
Six months ended June 30, 2018 | NA |
|
| $ | 667 |
|
| $ | 963 |
|
| $ | 642 |
|
| $ | 338 |
|
21
The Company’s effective income tax rate for the three months ended September 30, 2017 was 28.8%, compared with 37.0% for the three months ended September 30, 2016. For the nine months ended September 30, 2017, the effective income tax rate was 36.1%, compared to 35.8% for the nine months ended September 30, 2016. The effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, changes in pretax income in countriesjurisdictions with varying statutory tax rates, the impact of U.S. state and local taxes, and other differences related to the recognition of income and expense between U.S. GAAP and tax. tax accounting.
Compared with the third quarter of 2016, the lowerThe Company’s effective income tax rate for the thirdthree months ended June 30, 2019 was 17.0%, compared with 43.9% for the three months ended June 30, 2018. The higher effective income tax rate for the three months ended June 30, 2018 was primarily attributable to changes in forecasted annual pretax income from the first quarter of 20172018 to the second quarter of 2018. The Company also recorded tax expense related to the vesting of share-based compensation during the second quarter of 2019.
The Company’s effective income tax rate for the six months ended June 30, 2019 was 17.7%, compared with 15.2% for the six months ended June 30, 2018. The change in the effective income tax rate for the six months ended June 30, 2019 was primarily relatedattributable to the impact of share-based payment transactions andvarious non-deductible transaction costs associated withexpenses for U.S. tax purposes when measured against annual forecasted pretax book income in the SSE merger,computation of the effective tax rate, as well as true-up adjustmentsthe impact of non-U.S. valuation allowances booked in 2018.
The Company continues to monitor income tax developments in the United States and other countries affecting the Company. In December 2017, the United States enacted U.S. taxes forTax Reform, which materially impacted the consolidated financial statements by decreasing the U.S. corporate statutory tax return filingsrate and significantly affecting future periods. The Company expects several proposed U.S. Treasury regulations under U.S. Tax Reform that were issued during 2018 to be finalized during 2019, as well as additional regulations to be proposed and finalized during 2019. The Company will incorporate into its future financial statements the impacts, if any, of these regulations and additional authoritative guidance when finalized.
14. 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 third quarterperiod, excluding non-vested shares of 2017. restricted stock.
Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock, 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 effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class method, assuming a reallocation of undistributed earnings to common stockholders after considering the dilutive effect of potential common shares other than non-vested shares of restricted stock.
The following table presents information necessary to calculate net loss per share for the three and six months ended June 30, 2019 and 2018 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 |
|
| Six Months Ended |
| ||||||||||
| June 30, |
|
| June 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
BASIC EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributed to common stockholders | $ | (49,447 | ) |
| $ | (10,713 | ) |
| $ | (78,061 | ) |
| $ | (45,130 | ) |
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock |
| 207,499 |
|
|
| 220,093 |
|
|
| 209,671 |
|
|
| 220,436 |
|
Basic net loss per common share | $ | (0.24 | ) |
| $ | (0.05 | ) |
| $ | (0.37 | ) |
| $ | (0.21 | ) |
DILUTED EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributed to common stockholders | $ | (49,447 | ) |
| $ | (10,713 | ) |
| $ | (78,061 | ) |
| $ | (45,130 | ) |
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock |
| 207,499 |
|
|
| 220,093 |
|
|
| 209,671 |
|
|
| 220,436 |
|
Add dilutive effect of potential common shares |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Weighted average number of diluted common shares outstanding |
| 207,499 |
|
|
| 220,093 |
|
|
| 209,671 |
|
|
| 220,436 |
|
Diluted net loss per common share | $ | (0.24 | ) |
| $ | (0.05 | ) |
| $ | (0.37 | ) |
| $ | (0.21 | ) |
Potentially dilutive securities excluded as anti-dilutive |
| 10,289 |
|
|
| 9,903 |
|
|
| 10,289 |
|
|
| 9,903 |
|
15. Business Segments
At June 30, 2019, the Company had three reportable 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.
13.
The following tables summarize selected financial information relating to the Company’s business segments (in thousands):
| Three Months Ended |
|
| Six Months Ended |
| ||||||||||
| June 30, |
|
| June 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling | $ | 348,494 |
|
| $ | 350,340 |
|
| $ | 721,237 |
|
| $ | 678,493 |
|
Pressure pumping |
| 251,008 |
|
|
| 425,303 |
|
|
| 498,609 |
|
|
| 832,087 |
|
Directional drilling |
| 50,218 |
|
|
| 52,705 |
|
|
| 103,177 |
|
|
| 101,321 |
|
Other operations (1) |
| 27,852 |
|
|
| 31,717 |
|
|
| 63,243 |
|
|
| 61,370 |
|
Elimination of intercompany revenues (2) |
| (1,807 | ) |
|
| (5,647 | ) |
|
| (6,330 | ) |
|
| (9,689 | ) |
Total revenues | $ | 675,765 |
|
| $ | 854,418 |
|
| $ | 1,379,936 |
|
| $ | 1,663,582 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling | $ | 16,494 |
|
| $ | (251 | ) |
| $ | 37,711 |
|
| $ | (17,354 | ) |
Pressure pumping |
| (14,408 | ) |
|
| 20,637 |
|
|
| (33,176 | ) |
|
| 46,026 |
|
Directional drilling |
| (5,290 | ) |
|
| (7,678 | ) |
|
| (10,957 | ) |
|
| (12,591 | ) |
Other operations |
| (7,317 | ) |
|
| (4,777 | ) |
|
| (12,521 | ) |
|
| (8,866 | ) |
Corporate |
| (24,939 | ) |
|
| (24,064 | ) |
|
| (48,636 | ) |
|
| (47,871 | ) |
Other operating (expenses) income, net (3) |
| (9,071 | ) |
|
| 7,129 |
|
|
| (335 | ) |
|
| 9,550 |
|
Provision for bad debts |
| (3,594 | ) |
|
| — |
|
|
| (3,594 | ) |
|
| — |
|
Interest income |
| 1,756 |
|
|
| 2,360 |
|
|
| 2,788 |
|
|
| 3,783 |
|
Interest expense |
| (13,298 | ) |
|
| (12,667 | ) |
|
| (26,282 | ) |
|
| (26,292 | ) |
Other |
| 92 |
|
|
| 216 |
|
|
| 209 |
|
|
| 385 |
|
Loss before income taxes | $ | (59,575 | ) |
| $ | (19,095 | ) |
| $ | (94,793 | ) |
| $ | (53,230 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and impairment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling | $ | 128,402 |
|
| $ | 130,938 |
|
| $ | 258,719 |
|
| $ | 261,855 |
|
Pressure pumping |
| 56,185 |
|
|
| 57,862 |
|
|
| 116,320 |
|
|
| 114,384 |
|
Directional drilling |
| 10,870 |
|
|
| 11,874 |
|
|
| 21,237 |
|
|
| 22,776 |
|
Other operations |
| 11,457 |
|
|
| 9,829 |
|
|
| 23,245 |
|
|
| 19,143 |
|
Corporate |
| 1,774 |
|
|
| 1,881 |
|
|
| 3,577 |
|
|
| 4,118 |
|
Total depreciation, depletion, amortization and impairment | $ | 208,688 |
|
| $ | 212,384 |
|
| $ | 423,098 |
|
| $ | 422,276 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling | $ | 47,664 |
|
| $ | 121,095 |
|
| $ | 123,389 |
|
| $ | 196,342 |
|
Pressure pumping |
| 38,802 |
|
|
| 56,195 |
|
|
| 70,202 |
|
|
| 81,118 |
|
Directional drilling |
| 3,450 |
|
|
| 10,034 |
|
|
| 5,562 |
|
|
| 22,863 |
|
Other operations |
| 6,230 |
|
|
| 7,311 |
|
|
| 14,003 |
|
|
| 16,707 |
|
Corporate |
| 773 |
|
|
| 227 |
|
|
| 2,104 |
|
|
| 753 |
|
Total capital expenditures | $ | 96,919 |
|
| $ | 194,862 |
|
| $ | 215,260 |
|
| $ | 317,783 |
|
| June 30, 2019 |
|
| December 31, 2018 |
| ||
Identifiable assets: |
|
|
|
|
|
|
|
Contract drilling | $ | 3,620,264 |
|
| $ | 3,817,638 |
|
Pressure pumping |
| 849,006 |
|
|
| 921,237 |
|
Directional drilling |
| 221,556 |
|
|
| 239,341 |
|
Other operations |
| 171,412 |
|
|
| 177,374 |
|
Corporate (4) |
| 329,545 |
|
|
| 314,276 |
|
Total assets | $ | 5,191,783 |
|
| $ | 5,469,866 |
|
(1) | Other operations includes the Company’s oilfield rentals business, pipe handling components and related technology business, the electrical controls and automation business, the oil and natural gas working interests and Middle East organizational activities. |
(2) | Intercompany revenues consists of contract drilling and revenues from other operations for services provided to contract drilling, pressure pumping and within other operations. |
(3) | Other operating income, net 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 certain legal-related expenses and settlements, net of insurance reimbursements. |
(4) | Corporate assets primarily include cash on hand and certain property and equipment. |
16. 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 SeptemberJune 30, 20172019 and December 31, 20162018 is set forth below (in thousands):
| September 30, 2017 |
|
| December 31, 2016 |
| June 30, 2019 |
|
| December 31, 2018 |
| ||||||||||||||||||||
| Carrying |
|
| Fair |
|
| Carrying |
|
| Fair |
| Carrying |
|
| Fair |
|
| Carrying |
|
| Fair |
| ||||||||
| Value |
|
| Value |
|
| Value |
|
| Value |
| Value |
|
| Value |
|
| Value |
|
| Value |
| ||||||||
3.95% Senior Notes | $ | 525,000 |
|
| $ | 526,235 |
|
| $ | 525,000 |
|
| $ | 482,488 |
| |||||||||||||||
4.97% Series A Senior Notes | $ | 300,000 |
|
| $ | 305,440 |
|
| $ | 300,000 |
|
| $ | 283,534 |
|
| 300,000 |
|
|
| 306,592 |
|
|
| 300,000 |
|
|
| 300,043 |
|
4.27% Series B Senior Notes |
| 300,000 |
|
|
| 296,172 |
|
|
| 300,000 |
|
|
| 263,194 |
|
| 300,000 |
|
|
| 305,603 |
|
|
| 300,000 |
|
|
| 293,900 |
|
Total debt | $ | 600,000 |
|
| $ | 601,612 |
|
| $ | 600,000 |
|
| $ | 546,728 |
| $ | 1,125,000 |
|
| $ | 1,138,430 |
|
| $ | 1,125,000 |
|
| $ | 1,076,431 |
|
The fair values of the 3.95% Senior Notes at June 30, 2019 and December 31, 2018 are based on discounted cash flows associated with the notes using the 4.15% market rate of interest at June 30, 2019 and the 5.07% market rate of interest at December 31, 2018. The fair value estimates of the 3.95% Senior Notes are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting. The fair values of the Series A Notes and Series B Notes at SeptemberJune 30, 20172019 and December 31, 20162018 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 4.32%4.13% at SeptemberJune 30, 20172019 and 6.65%4.97% at December 31, 2016.2018. For the Series B Notes, the current market rates used in measuring this fair value were 4.58%3.96% at SeptemberJune 30, 20172019 and 7.02%4.92% at December 31, 2016.2018. 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.
22
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 has identified and reviewed revenue streams and is in the process of performing a detailed analysis of a subset of contracts representative of the revenue streams. At this time, the Company expects to adopt this new revenue guidance utilizing the modified retrospective method of adoption in the first quarter of 2018. The Company is currently evaluating the impact that the new revenue standard will have on its consolidated financial statements upon adoption.
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 will require the Company to separate 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 previously disclosed its intention to adopt this standard at the same time as it adopts the new revenue standard discussed above; however, the Company now expects to adopt this new guidance in the first quarter of 2019. The Company is currently evaluating the impact that this new guidance will have on its consolidated financial statements.
In November 2015, the FASB issued an accounting standards update to provide guidance for the presentation of deferred tax liabilities and assets. Under this guidance, for a particular tax-paying component of an entity and within a particular tax jurisdiction, all deferred tax liabilities and assets, as well as any related valuation allowance, shall be offset and presented as a single noncurrent amount. This guidance became effective for the Company during the three months ended March 31, 2017. The adoption of this update was applied retrospectively, resulting in the reclassification of $36.4 million from current deferred tax assets as of December 31, 2016. Of this amount, $4.1 million was reclassified to long-term deferred tax assets and $32.3 million was reclassified to long-term deferred tax liabilities.
In March 2016, the FASB issued an accounting standards update to provide guidance for the accounting for share-based payment transactions, including the related income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This guidance became effective for the Company during the three months ended March 31, 2017. The Company believes this guidance has caused and will continue to cause volatility in its effective tax rates and diluted earnings per share due to the tax effects related to share-based payments being recorded in the statement of operations. The volatility in future periods will depend on the Company’s stock price and the number of shares that vest in the case of restricted stock, restricted stock units and performance stock units, or the number of shares that are exercised in the case of stock options.
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 is not expected to have a material impact on the Company’s consolidated financial statements.
In January 2017, the FASB issued an accounting standards update to eliminate Step 2 from the goodwill impairment test. An entity will now perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value, but the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The requirements in this update are effective during interim and annual periods in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates on or after January 1, 2017. The Company adopted this update in 2017, which did not have a material impact on the Company’s consolidated financial statements.
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 is not expected to have a material impact on the Company’s consolidated financial statements.
23
SPECIAL 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. As used in this Report, “the Company,” “us,” “we,” our” and like terms refer collectively to Patterson-UTI Energy, Inc. and its consolidated subsidiaries. Patterson-UTI Energy, Inc. conducts its operations through its wholly-owned subsidiaries and has no employees or independent business operations. 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,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”,“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.
On April 20, 2017, we completed our previously announced merger with Seventy Seven Energy Inc. (“SSE”), pursuant to which 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”). On October 11, 2017, we completed our acquisition of Multi-Shot, LLC (“MS Directional”). These forward-looking statements include, without limitation, our expectations with respect to:
synergies, costs and other anticipated financial impacts of the SSE merger and the MS Directional acquisition;
•future financial and operating results of the combined company; and
•the combined company’s plans, objectives, expectations and intentions with respect to future operations and services.
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 also include, those set forth under “Risk Factors,” in Item 1A of Part II of this Report, as well, as among others, risks and uncertainties relating to:
the diversion of management time on merger-related issues;
• | adverse oil and natural gas industry conditions; |
the ultimate timing, outcome and results of integrating our operations with those of SSE and MS Directional;
the effects of our business combination with SSE and MS Directional acquisition, including the combined company’s future financial condition, results of operations, strategy and plans;
potential adverse reactions or changes to business relationships resulting from the SSE merger and MS Directional acquisition;
expected benefits from the SSE merger and MS Directional acquisition and our ability to realize those benefits;
the results of merger-related litigation, settlements and investigations;
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;
interest rate volatility;
compliance with covenants under our debt agreements;
excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction;
equipment specialization 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;
24
• | 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; |
• | excess availability of land drilling rigs, pressure pumping and directional drilling equipment, including as a result of reactivation, improvement or construction; |
• | competition and demand for our services; |
• | strength and financial resources of competitors; |
• | utilization, margins and planned capital expenditures; |
• | liabilities from operational risks for which we do not have and receive full indemnification or insurance; |
• | 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); |
• | the ability to realize backlog; |
• | specialization of methods, equipment and services and new technologies; |
• | shortages, delays in delivery, and interruptions in supply, of equipment and materials; |
• | cybersecurity events; |
• | the ability to retain management and field personnel; |
• | loss of key customers; |
• | synergies, costs and financial and operating impacts of acquisitions; |
• | difficulty in building and deploying new equipment; |
• | governmental regulation; |
• | environmental risks and ability to satisfy future environmental costs; |
• | legal proceedings and actions by governmental or other regulatory agencies; |
• | technology-related disputes; |
• | the ability to effectively identify and enter new markets; |
• | weather; |
• | operating costs; |
• | expansion and development trends of the oil and natural gas industry; |
weather;
• | ability to obtain insurance coverage on commercially reasonable terms; |
shortages, delays in delivery, and interruptions in supply, of equipment and materials;
• | financial flexibility; |
the ability to retain management and field personnel;
• | interest rate volatility; |
the ability to effectively identify and enter new markets;
• | adverse credit and equity market conditions; |
the ability to realize backlog;
• | availability of capital and the ability to repay indebtedness when due; |
strength and financial resources of competitors;
• | compliance with covenants under our debt agreements; and |
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;
competition and demand for our services;
liabilities from operations 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
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”).
• | 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, 2016,2018 and may be contained in our Quarterly Reports on Form 10-Q forfuture filings with the three months ended March 31, 2017 and June 30, 2017 and other SEC filings.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.
25
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Recent Developments — On October 11, 2017, we acquired all of the issued and outstanding limited liability company interests of Multi-Shot, LLC (“MS Directional”). The aggregate consideration paid by us to the sellers consisted of $75 million in cash and 8,798,391 shares of our common stock. The purchase price is 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 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 $262 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.
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 have acquired a fleet of 91 drilling rigs, 36 of which we consider to be APEX® class rigs. Additionally, through the SSE merger, we have 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 data in the discussion and analysis below includes the results of operations of the SSE business since April 20, 2017.
On January 27, 2017, we completed an offering of 18.2 million shares of our common stock and raised net proceeds of $472 million. We used the net proceeds of the offering to repay SSE’s outstanding indebtedness of approximately $472 million.
On January 24, 2017, we entered into an agreement with certain lenders under our revolving credit facility to increase the aggregate commitments under our revolving credit facility to approximately $595.8 million, subject to the satisfaction of certain conditions. The aggregate commitment increase became effective on April 20, 2017 upon the consummation of the SSE merger and the repayment and termination of the SSE credit facility. On April 20, 2017, we entered into Amendment No. 4 to Credit Agreement which permitted outstanding letters of credit under the SSE credit facility to be deemed to be incurred under our credit facility and increased the amount of the accordion feature of our revolving credit facility to permit aggregate commitments to be increased to an amount not to exceed $700 million (subject to satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). On April 20, 2017, we also entered into an additional commitment increase agreement with certain of our lenders pursuant to which total commitments available under our revolving credit facility (after giving effect to both commitment increases) increased to $632 million through September 2017 and to $490 million through March 2019. On October 27, 2017, we entered into an additional commitment increase agreement with certain of our lenders pursuant to which total commitments available under our revolving credit facility increased to $500 million through March 2019.
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 substantially from the lows experienced in the first quarter of 2016. During the fourth quarter of 2016, the Organization of Petroleum Exporting Countries (“OPEC”) and certain non-OPEC countries, including Russia, announced an agreement to cut oil production, resulting in an increase in oil prices. Oil prices averaged $48.14 per barrel in the third quarter of 2017.
Our rig count declined significantly during the industry downturn that began in late 2014, but had improved on a monthly basis from May 2016 to June 2017. For the third quarter of 2017, our average rig count improved to 161 rigs, which was an increase from an average of 146 rigs in the second quarter of 2017, where the second quarter rig count did not include the full quarter contribution from the rigs acquired in the SSE merger. Term contracts have supported our operating rig count during the last three years. Based on contracts currently in place, we expect an average of 87 rigs operating under term contracts during the fourth quarter of 2017 and an average of 53 rigs operating under term contracts during the twelve months ending September 30, 2018.
26
Activity levels in our pressure pumping business have also improved. Looking forward, we expect to see further increases in activity across the industry, especially in the Permian Basin. We reactivated two frac spreads during the third quarter, and we plan to reactivate one additional frac spread during the fourth quarter. With the addition of these three frac spreads, we expect to exit 2017 with 23 active frac spreads or approximately 1.25 million hydraulic fracturing horsepower active.
ManagementOverview— 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 in the United States and a large fleet of pressure pumping equipment. Our contract drilling business operates in the continental United States and western Canada, and, from time to time, we are pursuingpursue contract drilling opportunities outside of North America. Our pressure pumping business operates primarily in Texas and the Mid-Continent and Appalachian regions. In addition,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 statistical accuracy of horizontal wellbore placement. We have other operations wherethrough which we provide oilfield rental tools and wein select markets in the United States. We also manufacture and sell pipe handling components and related technology to drilling contractors, and provide electrical controls and automation to the energy, marine and mining industries, 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.
OnOil prices have recovered from a 12-year low of $26.19 in February 2016 and reached a high of $77.41 in June 2018. Oil prices remain volatile, as the closing price of oil reached a fourth quarter 2018 high of $76.40 per barrel on October 11, 2017, we acquired MS Directional,3, 2018, before declining by 42% over the course of three months to reach a leading directionallow of $44.48 per barrel in late December 2018. Oil prices averaged $59.88 per barrel in the second quarter of 2019 and closed at $55.87 per barrel on July 22, 2019. Despite oil prices in the mid-$50s to low-$60s, drilling services companyand pressure pumping activity has recently declined, largely as a result of reduced customer spending.
Our average active rig count for the second quarter of 2019 was 158 rigs, which included 157 rigs operating in the United States and one rig operating in Canada. This was a decrease from our average active rig count for the first quarter of 2019 of 175, which included 174 rigs in the United States and one rig in Canada. We believe our customers are slowing drilling and completion activity to smooth their spending run rate and reduce the risk of budget exhaustion later in 2019. We expect our rig count to average 142 rigs during the third quarter. Based on term contracts (contracts with operationsa duration of six months or more) currently in most major producing onshore oilplace, we expect an average of 92 rigs operating under term contracts during the third quarter of 2019 and gas basins. MS Directional provides a comprehensive suitean average of directional58 rigs operating under term contracts during the twelve months ending June 30, 2020.
In pressure pumping, we ended the second quarter with 15 active spreads compared to 16 at the end of the first quarter. Across the pressure pumping industry, we expect completion activity will follow drilling services, including directional drilling, downhole performance motors, directional surveying, measurement-while-drilling, and wireline steering tools.activity lower in the third quarter. We expect to reportmaintain 15 active spreads during the third quarter, but we expect lower utilization of the active spreads will negatively impact pressure pumping revenues and margin.
Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas. During periods of improved oil and natural gas 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 oil and natural gas prices deteriorate, the demand for our services generally weakens, and we experience downward pressure on pricing for our services.
The North American oil and natural gas services industry is cyclical and, at times, experiences downturns in demand. During these periods, there has been substantially more oil and natural gas service equipment available than necessary to meet demand. As a result, oil and natural gas service contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. Currently, there is an excess supply of drilling rigs, pressure pumping equipment and directional drilling equipment. We cannot predict either the future level of demand for our oil and natural gas services or future conditions in the oil and natural gas service businesses.
We are highly impacted by operational risks, competition, labor issues, weather, the availability of products used 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 this business as a separate segment beginning withoperations. Please see “Risk Factors” included in Item 1A of our Annual Report on Form 10-K for the fourth quarterfiscal year ended December 31, 2018.
For the three and six months ended June 30, 2019 and 2018, our operating revenues consisted of 2017.the following (dollars in thousands):
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||||||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||||||||||||||||||
Contract drilling | $ | 348,138 |
|
|
| 51.5 | % |
| $ | 349,922 |
|
|
| 40.9 | % |
| $ | 720,530 |
|
|
| 52.2 | % |
| $ | 677,725 |
|
|
| 40.7 | % |
Pressure pumping |
| 251,008 |
|
|
| 37.2 | % |
|
| 425,303 |
|
|
| 49.8 | % |
|
| 498,609 |
|
|
| 36.1 | % |
|
| 832,087 |
|
|
| 50.0 | % |
Directional drilling |
| 50,218 |
|
|
| 7.4 | % |
|
| 52,705 |
|
|
| 6.2 | % |
|
| 103,177 |
|
|
| 7.5 | % |
|
| 101,321 |
|
|
| 6.1 | % |
Other operations |
| 26,401 |
|
|
| 3.9 | % |
|
| 26,488 |
|
|
| 3.1 | % |
|
| 57,620 |
|
|
| 4.2 | % |
|
| 52,449 |
|
|
| 3.2 | % |
| $ | 675,765 |
|
|
| 100.0 | % |
| $ | 854,418 |
|
|
| 100.0 | % |
| $ | 1,379,936 |
|
|
| 100.0 | % |
| $ | 1,663,582 |
|
|
| 100.0 | % |
Contract Drilling
Contract drilling operationsrevenues accounted for 44.0%51.5% of our consolidated thirdsecond quarter 20172019 revenues, and increased 143.9%contract drilling revenues decreased 0.5% over the comparable 20162018 period.
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. The U.S. land rig industry refers to certain high specification rigs as “super-spec” rigs. We consider a super-spec rig to be a 1,500 horsepower, AC powered rig that has at least a 750,000 pound hookload, a 7,500 psi circulating system, and is pad capable. As of SeptemberJune 30, 2017,2019, our rig fleet included 198 APEX® class rigs. We expect to add one new APEX® rig to our fleet during the fourth quarter of 2017. Four of the previously announced seven APEX-XK® upgrades have been delivered and the remaining three rigs, are under contract. We also have contracts to upgrade two additional rigs to APEX PK™ rigs, with a box-on-box substructure and integrated walking system for enhanced performance on multi-well pads, both of which are expected to be delivered in the first half of 2018.150 were considered super-spec rigs.
We maintain a backlog of commitments for contract drilling revenuesservices under term contracts, which we define as contracts with a fixed termduration of six months or more. Our contract drilling backlog as of SeptemberJune 30, 20172019 was approximately $471$720 million. Approximately 17%35% of the total SeptemberJune 30, 20172019 backlog is reasonably expected to remain at SeptemberJune 30, 2018.2020. 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 fees for other feesservices such as for mobilization, other than initial 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. For contracts that contain variable dayrate pricing, our backlog calculation uses the dayrate in effect for periods where the dayrate is fixed, and, for periods that remain subject to variable pricing, uses the commodity price in effect at June 30, 2019. 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.
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, |
• | development of new technologies that enhance drilling efficiency, and |
• | construction of new technology drilling rigs. |
Pressure Pumping
Pressure pumping operationsrevenues accounted for 52.9%37.2% of our consolidated thirdsecond quarter 20172019 revenues and increased 363.7% overdecreased 41.0% from the comparable 20162018 period. As of SeptemberJune 30, 2017,2019, we had approximately 1.6 million hydraulic horsepower in our pressure pumping fleet (approximately 1.5 millionfleet. The pressure pumping market showed signs of whichoversupply in the second half of 2018 and was hydraulic fracturing horsepower). We have increasedoversupplied in the horsepowerfirst six months of 2019. In response to oversupplied market conditions, we reduced the number of active pressure pumping spreads to 15 early in the second quarter of 2019.
Directional Drilling
Directional drilling revenues accounted for 7.4% of our pressure pumpingconsolidated second quarter 2019 revenues and decreased 4.7% from the comparable 2018 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, measurement-while-drilling, and wireline steering tools, and we provide services that improve the statistical accuracy of horizontal wellbore placement.
Other Operations
Other operations revenues accounted for 3.9% of our consolidated second quarter 2019 revenues and decreased 0.3% from the comparable 2018 period. Our oilfield rentals business, with a fleet by more than thirteen-fold sinceof premium oilfield rental tools, provides the beginning of 2009. In recent years, the industry-wide addition of new pressure pumping equipmentlargest revenue contribution to the marketplaceour other operations and lowerprovides specialized services for land-based 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 led to a modest undersupply of pressure pumping equipment in the U.S. onshore market.
27
drilling, completion and workover activities. Other operations revenue accounted for 3.1%also includes the results of our consolidated third quarter 2017 revenueselectrical controls and increased 388.7% overautomation business, the comparable 2016 period.results of our pipe handling components and related technology business, and the results of our ownership, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.
For the three and ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, our operating revenuesloss consisted of the following (in thousands):
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| Three Months Ended June 30, |
|
| Six Months Ended June 30, | ||||||||||||||||||||||||||||||||||||||
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| 2019 |
|
| 2018 |
|
| 2019 | 2018 | ||||||||||||||||||||||||||||
Contract drilling | $ | 301,614 |
|
|
| 44.0 | % |
| $ | 123,684 |
|
|
| 60.0 | % |
| $ | 730,453 |
|
|
| 46.5 | % |
| $ | 407,578 |
|
|
| 60.9 | % | $ | 16,494 |
|
| $ | (251 | ) |
| $ | 37,711 |
|
| $ | (17,354 | ) |
|
Pressure pumping |
| 362,441 |
|
|
| 52.9 | % |
|
| 78,165 |
|
|
| 37.9 | % |
|
| 793,659 |
|
|
| 50.6 | % |
|
| 248,428 |
|
|
| 37.2 | % |
| (14,408 | ) |
|
| 20,637 |
|
|
| (33,176 | ) |
|
| 46,026 |
|
|
Directional drilling |
| (5,290 | ) |
|
| (7,678 | ) |
|
| (10,957 | ) |
|
| (12,591 | ) |
| |||||||||||||||||||||||||||||||
Other operations |
| 20,934 |
|
|
| 3.1 | % |
|
| 4,284 |
|
|
| 2.1 | % |
|
| 45,238 |
|
|
| 2.9 | % |
|
| 12,973 |
|
|
| 1.9 | % |
| (7,317 | ) |
|
| (4,777 | ) |
|
| (12,521 | ) |
|
| (8,866 | ) |
|
Corporate |
| (37,604 | ) |
|
| (16,935 | ) |
|
| (52,565 | ) |
|
| (38,321 | ) |
| |||||||||||||||||||||||||||||||
| $ | 684,989 |
|
|
| 100.0 | % |
| $ | 206,133 |
|
|
| 100.0 | % |
| $ | 1,569,350 |
|
|
| 100.0 | % |
| $ | 668,979 |
|
|
| 100.0 | % | $ | (48,125 | ) |
| $ | (9,004 | ) |
| $ | (71,508 | ) |
| $ | (31,106 | ) |
|
Additional discussion of our operating revenues and operating loss follows in the “Results of Operations” section.
Our consolidated net loss for the second quarter of 2019 was $49.4 million compared to a net loss of $10.7 million for the second quarter of 2018.
Results of Operations
The following tables summarize results of operations by business segment for the three months ended June 30, 2019 and 2018:
Contract Drilling | 2019 |
|
| 2018 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 348,138 |
|
| $ | 349,922 |
|
|
| (0.5 | )% |
Direct operating costs |
| 201,792 |
|
|
| 217,674 |
|
|
| (7.3 | )% |
Margin (1) |
| 146,346 |
|
|
| 132,248 |
|
|
| 10.7 | % |
Selling, general and administrative |
| 1,450 |
|
|
| 1,561 |
|
|
| (7.1 | )% |
Depreciation, amortization and impairment |
| 128,402 |
|
|
| 130,938 |
|
|
| (1.9 | )% |
Operating income (loss) | $ | 16,494 |
|
| $ | (251 | ) |
| NA |
| |
Operating days (2) |
| 14,385 |
|
|
| 15,998 |
|
|
| (10.1 | )% |
Average revenue per operating day | $ | 24.20 |
|
| $ | 21.87 |
|
|
| 10.6 | % |
Average direct operating costs per operating day | $ | 14.03 |
|
| $ | 13.61 |
|
|
| 3.1 | % |
Average margin per operating day (1) | $ | 10.17 |
|
| $ | 8.27 |
|
|
| 23.1 | % |
Average rigs operating |
| 158 |
|
|
| 176 |
|
|
| (10.1 | )% |
Capital expenditures | $ | 47,664 |
|
| $ | 121,095 |
|
|
| (60.6 | )% |
(1) | Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per operating day is defined as margin divided by operating days. |
(2) | A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day. |
Generally, the profitability of our business has been impacted most by two primary factorsrevenues in our contract drilling segment:segment are most impacted by two primary factors: our average number of rigs operating and our average revenue per operating day. During the thirdsecond quarter of 2017,2019, our average number of rigs operating was 161,158, compared to 61176 in the thirdsecond quarter of 2016.2018. Our average revenue per operating day was $20,320is largely dependent on the pricing terms of our rig contracts.
Revenues decreased slightly due to a decrease in operating days. Average revenue per operating day increased compared to the thirdsecond quarter of 2017, compared2018. This increase was supported by our upgrades of additional rigs to $21,870super-spec capability.
Capital expenditures decreased from the comparable 2018 period primarily due to upgrading rigs to super-spec capability in 2018.
Pressure Pumping | 2019 |
|
| 2018 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 251,008 |
|
| $ | 425,303 |
|
|
| (41.0 | )% |
Direct operating costs |
| 206,137 |
|
|
| 342,885 |
|
|
| (39.9 | )% |
Margin (1) |
| 44,871 |
|
|
| 82,418 |
|
|
| (45.6 | )% |
Selling, general and administrative |
| 3,094 |
|
|
| 3,919 |
|
|
| (21.1 | )% |
Depreciation, amortization and impairment |
| 56,185 |
|
|
| 57,862 |
|
|
| (2.9 | )% |
Operating income (loss) | $ | (14,408 | ) |
| $ | 20,637 |
|
| NA |
| |
Fracturing jobs |
| 122 |
|
|
| 217 |
|
|
| (43.8 | )% |
Other jobs |
| 193 |
|
|
| 264 |
|
|
| (26.9 | )% |
Total jobs |
| 315 |
|
|
| 481 |
|
|
| (34.5 | )% |
Average revenue per fracturing job | $ | 2,028.33 |
|
| $ | 1,932.62 |
|
|
| 5.0 | % |
Average revenue per other job | $ | 18.40 |
|
| $ | 22.44 |
|
|
| (18.0 | )% |
Average revenue per total job | $ | 796.85 |
|
| $ | 884.21 |
|
|
| (9.9 | )% |
Average direct operating costs per total job | $ | 654.40 |
|
| $ | 712.86 |
|
|
| (8.2 | )% |
Average margin per total job (1) | $ | 142.45 |
|
| $ | 171.35 |
|
|
| (16.9 | )% |
Margin as a percentage of revenues (1) |
| 17.9 | % |
|
| 19.4 | % |
|
| (7.7 | )% |
Capital expenditures | $ | 38,802 |
|
| $ | 56,195 |
|
|
| (31.0 | )% |
(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 third quarter of 2016. The profitability ofrevenues in our pressure pumping segment has beenare most impacted most 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. Direct operating costs are also most impacted by these same factors. We completed 174122 fracturing jobs during the thirdsecond quarter of 2017,2019, compared to 84217 fracturing jobs duringin the thirdsecond quarter of 2016.2018. Our average revenue per fracturing job was $2.044$2.028 million in the thirdsecond quarter of 2017 and $906,4202019, compared to $1.933 million in the thirdsecond quarter of 2016. Our margin from contract drilling improved by $65.5 million2018.
Selling, general and our margin from pressure pumping improved by $71.2 million, comparedadministrative expenses decreased primarily as a result of cost reduction efforts. The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in the thirdsecond quarter of 2016. These improvements in margin2018 when activity levels were higher.
Directional Drilling | 2019 |
|
| 2018 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 50,218 |
|
| $ | 52,705 |
|
|
| (4.7 | )% |
Direct operating costs |
| 42,102 |
|
|
| 43,685 |
|
|
| (3.6 | )% |
Margin (1) |
| 8,116 |
|
|
| 9,020 |
|
|
| (10.0 | )% |
Selling, general and administrative |
| 2,536 |
|
|
| 4,824 |
|
|
| (47.4 | )% |
Depreciation and amortization |
| 10,870 |
|
|
| 11,874 |
|
|
| (8.5 | )% |
Operating loss | $ | (5,290 | ) |
| $ | (7,678 | ) |
|
| (31.1 | )% |
Capital expenditures | $ | 3,450 |
|
| $ | 10,034 |
|
|
| (65.6 | )% |
(1) | Margin is defined as revenues less direct operating costs and excludes depreciation and amortization and selling, general and administrative expenses. |
Directional drilling revenue decreased by $2.5 million from the second quarter of 2018 due primarily to decreased job activity, partially offset by an increaseincreased revenue from Superior QC, LLC (“Superior QC”), which was acquired in the first quarter of 2018. Directional drilling direct operating costs decreased by $1.6 million from the second quarter of 2018 primarily due to cost reduction efforts.
Selling, general and administrative expense decreased from the second quarter of 2018 primarily as a result of cost reduction efforts. The decrease in capital expenditures was primarily due to higher capital expenditures in the second quarter of 2018 in response to market demand and equipment upgrades.
Other Operations | 2019 |
|
| 2018 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 26,401 |
|
| $ | 26,488 |
|
|
| (0.3 | )% |
Direct operating costs |
| 17,612 |
|
|
| 17,513 |
|
|
| 0.6 | % |
Margin (1) |
| 8,789 |
|
|
| 8,975 |
|
|
| (2.1 | )% |
Selling, general and administrative |
| 4,649 |
|
|
| 3,923 |
|
|
| 18.5 | % |
Depreciation, depletion, amortization and impairment |
| 11,457 |
|
|
| 9,829 |
|
|
| 16.6 | % |
Operating loss | $ | (7,317 | ) |
| $ | (4,777 | ) |
|
| 53.2 | % |
Capital expenditures | $ | 6,230 |
|
| $ | 7,311 |
|
|
| (14.8 | )% |
(1) | Margin is defined as revenues less direct operating costs and excludes depreciation, depletion, amortization and impairment and selling, general and administrative expenses. |
Depreciation, depletion, amortization and impairment expenses of $33.2expense in 2019 includes approximately $1.1 million an increase of selling, general and administrative expenses of $10.9 million and merger and integration expenses of $9.4 million. Our consolidated net loss for the third quarter of 2017 was $33.8 million, compared to a consolidated net loss of $84.1 million for the third quarter of 2016.
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, there continues to be uncertainty with respect to the global economic environment, andproperty impairments, whereas no oil and natural gas property impairments were recorded in 2018.
Corporate | 2019 |
|
| 2018 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Selling, general and administrative | $ | 23,165 |
|
| $ | 21,436 |
|
|
| 8.1 | % |
Merger and integration expenses | $ | — |
|
| $ | 747 |
|
|
| (100.0 | )% |
Depreciation | $ | 1,774 |
|
| $ | 1,881 |
|
|
| (5.7 | )% |
Other operating expenses (income), net |
|
|
|
|
|
|
|
|
|
|
|
Net gain on asset disposals | $ | (3,971 | ) |
| $ | (7,062 | ) |
|
| (43.8 | )% |
Legal-related expenses and settlements, net of insurance reimbursements |
| — |
|
|
| 3,441 |
|
|
| (100.0 | )% |
Research and development |
| 371 |
|
|
| — |
|
|
| 100 | % |
Other |
| 12,671 |
|
|
| (3,508 | ) |
| NA |
| |
Other operating expenses (income), net | $ | 9,071 |
|
| $ | (7,129 | ) |
| NA |
| |
Provision for bad debts | $ | 3,594 |
|
| $ | — |
|
|
| 100.0 | % |
Interest income | $ | 1,756 |
|
| $ | 2,360 |
|
|
| (25.6 | )% |
Interest expense | $ | 13,298 |
|
| $ | 12,667 |
|
|
| 5.0 | % |
Other income | $ | 92 |
|
| $ | 216 |
|
|
| (57.4 | )% |
Capital expenditures | $ | 773 |
|
| $ | 227 |
|
|
| 240.5 | % |
Selling, general and administrative expense increased in 2019 primarily due to an increase in compensation related expenses. Merger and integration expenses incurred in 2018 are related to the Seventy Seven Energy Inc. (“SSE”) merger. Other operating expenses (income), net 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 2019 reflect gains on disposal of drilling equipment. Legal-related expenses and settlements in 2018 includes insurance deductibles and investigation costs related to an accident at a drilling site in January 2018.
Other operating expenses (income), net includes a $12.7 million charge recorded in the quarter ended June 30, 2019 related to a 2017 capacity reservation agreement that required a cash deposit to increase our access to finer grades of sand for our pressure pumping business. As market prices for sand have substantially decreased since 2017, we have purchased lower cost sand outside of this capacity reservation contract and have revalued the deposit at its expected realizable value. Other operating expenses (income), net also includes a $3.5 million gain recorded in the quarter ended June 30, 2018 related to the collection of a note receivable that had been recorded at a discount. A provision for bad debts was recognized in 2019 with respect to accounts receivable balances that are estimated to be uncollectible.
The following tables summarize results of operations by business segment for the six months ended June 30, 2019 and 2018:
Contract Drilling | 2019 |
|
| 2018 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 720,530 |
|
| $ | 677,725 |
|
|
| 6.3 | % |
Direct operating costs |
| 420,994 |
|
|
| 430,257 |
|
|
| (2.2 | )% |
Margin (1) |
| 299,536 |
|
|
| 247,468 |
|
|
| 21.0 | % |
Selling, general and administrative |
| 3,106 |
|
|
| 2,967 |
|
|
| 4.7 | % |
Depreciation, amortization and impairment |
| 258,719 |
|
|
| 261,855 |
|
|
| (1.2 | )% |
Operating income (loss) | $ | 37,711 |
|
| $ | (17,354 | ) |
| NA |
| |
Operating days |
| 30,172 |
|
|
| 31,216 |
|
|
| (3.3 | )% |
Average revenue per operating day | $ | 23.88 |
|
| $ | 21.71 |
|
|
| 10.0 | % |
Average direct operating costs per operating day | $ | 13.95 |
|
| $ | 13.78 |
|
|
| 1.2 | % |
Average margin per operating day (1) | $ | 9.93 |
|
| $ | 7.93 |
|
|
| 25.2 | % |
Average rigs operating |
| 167 |
|
|
| 172 |
|
|
| (2.9 | )% |
Capital expenditures | $ | 123,389 |
|
| $ | 196,342 |
|
|
| (37.2 | )% |
(1) | Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per operating day is defined as margin divided by operating days. |
During the first six months of 2019, our average number of rigs operating remain significantly below levelswas 167, compared to 172 in 2014.the same period of 2018. Our average rig revenue per operating day was $23,880 in the first half of 2019, compared to $21,710 in the first half of 2018. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts.
Revenues increased primarily due to higher average revenue per operating day supported by higher day rates on term contracts.
Capital expenditures decreased over the comparable 2018 period due to upgrading rigs to super-spec capability in 2018.
Pressure Pumping | 2019 |
|
| 2018 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 498,609 |
|
| $ | 832,087 |
|
|
| (40.1 | )% |
Direct operating costs |
| 408,885 |
|
|
| 663,855 |
|
|
| (38.4 | )% |
Margin (1) |
| 89,724 |
|
|
| 168,232 |
|
|
| (46.7 | )% |
Selling, general and administrative |
| 6,580 |
|
|
| 7,822 |
|
|
| (15.9 | )% |
Depreciation, amortization and impairment |
| 116,320 |
|
|
| 114,384 |
|
|
| 1.7 | % |
Operating income (loss) | $ | (33,176 | ) |
| $ | 46,026 |
|
| NA |
| |
Fracturing jobs |
| 286 |
|
|
| 421 |
|
|
| (32.1 | )% |
Other jobs |
| 456 |
|
|
| 544 |
|
|
| (16.2 | )% |
Total jobs |
| 742 |
|
|
| 965 |
|
|
| (23.1 | )% |
Average revenue per fracturing job | $ | 1,711.92 |
|
| $ | 1,948.88 |
|
|
| (12.2 | )% |
Average revenue per other job | $ | 19.73 |
|
| $ | 21.34 |
|
|
| (7.5 | )% |
Average revenue per total job | $ | 671.98 |
|
| $ | 862.27 |
|
|
| (22.1 | )% |
Average direct operating costs per total job | $ | 551.06 |
|
| $ | 687.93 |
|
|
| (19.9 | )% |
Average margin per total job (1) | $ | 120.92 |
|
| $ | 174.33 |
|
|
| (30.6 | )% |
Margin as a percentage of revenues (1) |
| 18.0 | % |
|
| 20.2 | % |
|
| (10.9 | )% |
Capital expenditures and acquisitions | $ | 70,202 |
|
| $ | 81,118 |
|
|
| (13.5 | )% |
(1) | Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues. |
We are also highlycompleted 286 fracturing jobs during the first six months of 2019, compared to 421 fracturing jobs in the same period of 2018. Our average revenue per fracturing job was $1.712 million in the first half of 2019, compared to $1.949 million in the first half of 2018.
Revenues and direct operating costs during the six months ended June 30, 2019 decreased primarily due to a decline in the number of fracturing jobs, as compared to the six months ended June 30, 2018. Average revenue and direct operating costs per job were impacted by operational risks, competition,lower demand, more customers self-sourcing products and decreases in product prices.
The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in the availabilitysecond quarter of excess2018 when activity levels were higher.
Directional Drilling | 2019 |
|
| 2018 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 103,177 |
|
| $ | 101,321 |
|
|
| 1.8 | % |
Direct operating costs |
| 87,704 |
|
|
| 81,374 |
|
|
| 7.8 | % |
Margin (1) |
| 15,473 |
|
|
| 19,947 |
|
|
| (22.4 | )% |
Selling, general and administrative |
| 5,193 |
|
|
| 9,762 |
|
|
| (46.8 | )% |
Depreciation and amortization |
| 21,237 |
|
|
| 22,776 |
|
|
| (6.8 | )% |
Operating loss | $ | (10,957 | ) |
| $ | (12,591 | ) |
|
| (13.0 | )% |
Capital expenditures | $ | 5,562 |
|
| $ | 22,863 |
|
|
| (75.7 | )% |
(1) | Margin is defined as revenues less direct operating costs and excludes depreciation and amortization and selling, general and administrative expenses. |
Directional drilling direct operating costs increased by $6.3 million from the six months ended June 30, 2018 due primarily to increased repairs and maintenance expense and labor costs.
Selling, general and administrative expense decreased in the six months ended June 30, 2019 primarily as a result of cost reduction efforts. The decrease in capital expenditures was primarily due to higher capital expenditures in 2018 in response to market demand and equipment labor issues, weather,upgrades.
Other Operations | 2019 |
|
| 2018 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 57,620 |
|
| $ | 52,449 |
|
|
| 9.9 | % |
Direct operating costs |
| 39,385 |
|
|
| 35,258 |
|
|
| 11.7 | % |
Margin (1) |
| 18,235 |
|
|
| 17,191 |
|
|
| 6.1 | % |
Selling, general and administrative |
| 7,511 |
|
|
| 6,914 |
|
|
| 8.6 | % |
Depreciation, depletion, amortization and impairment |
| 23,245 |
|
|
| 19,143 |
|
|
| 21.4 | % |
Operating loss | $ | (12,521 | ) |
| $ | (8,866 | ) |
|
| 41.2 | % |
Capital expenditures | $ | 14,003 |
|
| $ | 16,707 |
|
|
| (16.2 | )% |
(1) | Margin is defined as revenues less direct operating costs and excludes depreciation, depletion, amortization 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 an increase in the availabilityvolume of productservices provided and the acquisition of Current Power Solutions, Inc. in the fourth quarter of 2018. Capital expenditures decreased in 2019 primarily due to a decrease in oil and natural gas capital expenditures.
Corporate | 2019 |
|
| 2018 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Selling, general and administrative | $ | 45,059 |
|
| $ | 41,015 |
|
|
| 9.9 | % |
Merger and integration expenses | $ | — |
|
| $ | 2,738 |
|
|
| (100.0 | )% |
Depreciation | $ | 3,577 |
|
| $ | 4,118 |
|
|
| (13.1 | )% |
Other operating expenses (income), net |
|
|
|
|
|
|
|
|
|
|
|
Net gain on asset disposals | $ | (10,516 | ) |
| $ | (17,472 | ) |
|
| (39.8 | )% |
Legal-related expenses and settlements, net of insurance reimbursements |
| (3,471 | ) |
|
| 9,321 |
|
| NA |
| |
Research and development |
| 1,726 |
|
|
| 2,109 |
|
|
| (18.2 | )% |
Other |
| 12,596 |
|
|
| (3,508 | ) |
| NA |
| |
Other operating expenses (income), net | $ | 335 |
|
| $ | (9,550 | ) |
| NA |
| |
Provision for bad debts | $ | 3,594 |
|
| $ | — |
|
|
| 100.0 | % |
Interest income | $ | 2,788 |
|
| $ | 3,783 |
|
|
| (26.3 | )% |
Interest expense | $ | 26,282 |
|
| $ | 26,292 |
|
|
| (0.0 | )% |
Other income | $ | 209 |
|
| $ | 385 |
|
|
| (45.7 | )% |
Capital expenditures | $ | 2,104 |
|
| $ | 753 |
|
|
| 179.4 | % |
Selling, general and administrative expense increased in the six months ended June 30, 2019 due to an increase in compensation related expenses. Merger and integration expenses incurred in 2018 are related to the SSE merger, MS Directional, LLC (f/k/a Multi-Shot, LLC) acquisition and Superior QC acquisition. Other operating expenses (income), net 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 2019 reflect gains on disposal of drilling equipment. Legal-related expenses and settlements in 2018 includes insurance deductibles and investigation costs related to an accident at a drilling site in January 2018. Legal-related expenses and settlements in 2019 includes proceeds from insurance claims.
Other operating expenses (income), net includes a $12.7 million charge recorded in the quarter ended June 30, 2019 related to a 2017 capacity reservation agreement that required a cash deposit to increase our access to finer grades of sand for our pressure pumping business third party provider delays. As market prices for sand have substantially decreased since 2017, we have purchased lower cost sand outside of this capacity reservation contract and varioushave revalued the deposit at its expected realizable value. Other operating expenses (income), net includes a $3.5 million gain recorded in the quarter ended June 30, 2018 related to the collection of a note receivable that had been recorded at a discount. A provision for bad debts was recognized in 2019 with respect to accounts receivable balances that are estimated to be uncollectible.
Income Taxes
Our effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, that could materially adversely affect our business, financial condition, cash flowschanges in pretax income in jurisdictions with varying statutory tax rates, the impact of U.S. state and resultslocal taxes, and other differences related to the recognition of operations. Please see “Risk Factors” included in Part II of this Report, in Part I of our Annual Report on Form 10-K for the fiscal year ended December 31, 2016,income and in Part II of our Quarterly Reports on Form 10-Qexpense between U.S. GAAP and tax accounting.
Our effective income tax rate for the three months ended March 31, 2017 and June 30, 2017.2019 was 17.0%, compared with 43.9% for the three months ended June 30, 2018. The higher effective income tax rate for the three months ended June 30, 2018 was primarily attributable to changes in forecasted annual pretax income from the first quarter of 2018 to the second quarter of 2018. We also recorded tax expense related to the vesting of share-based compensation during the second quarter of 2019.
Our effective income tax rate for the six months ended June 30, 2019 was 17.7%, compared with 15.2% for the six months ended June 30, 2018. The change in the effective income tax rate for the six months ended June 30, 2019 was primarily attributable to the impact of various non-deductible expenses for U.S. tax purposes when measured against annual forecasted pretax book income in the computation of the effective tax rate, as well as the impact of non-U.S. valuation allowances booked in 2018.
We continue to monitor income tax developments in the United States and other countries affecting us. In December 2017, the United States enacted U.S. Tax Reform, which materially impacted the consolidated financial statements by decreasing the U.S. corporate statutory tax rate and significantly affecting future periods. We expect several proposed U.S. Treasury regulations under U.S. Tax Reform that were issued during 2018 to be finalized during 2019, as well as additional regulations to be proposed and finalized during 2019. We will incorporate into our future financial statements the impacts, if any, of these regulations and additional authoritative guidance when finalized.
Liquidity and Capital Resources
Our liquidity as of SeptemberJune 30, 20172019 included approximately $129$428 million in working capital, including $37.8$256 million of cash and cash equivalents, and $342approximately $600 million available under our revolving credit facility. As
On January 19, 2018, we completed an offering of September 30, 2017, we had debt$525 million aggregate principal amount of $144 million and $4.6our 2028 Notes. We used $239 million of letters of creditthe net proceeds from the offering to repay amounts outstanding under our revolving credit facility.
On April 20, 2017,As described below, on March 27, 2018, we entered into Amendment No. 4 to the Credit Agreementan amended and restated credit agreement, which permitted outstanding letters of credit under the SSE credit facility to be deemed to be incurred under our credit facility and increased the amount of the accordion feature of ouris a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to permit aggregate commitments to be increased to an amount not to exceed $700$600 million, (subject to satisfactionincluding a letter of certain conditions and the procurement of additional commitments from new or existing lenders). On April 20, 2017, we also entered into an agreement with certain of our lenders pursuant to which total commitments available under our revolving credit facility are $490that, at any time outstanding, is limited to $150 million, through March 2019. On October 27, 2017, we entered intoand a commitment increase agreement with certain of our lenders pursuantswing line facility that, at any time outstanding, is limited to which total commitments available under our revolving credit facility increased to $500 million through March 2019.$20 million.
We believe our current liquidity, together with cash expected to be generated from operations, 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. Given our current public market equity valuation, our cash balance and finance workingexpected future cash flow generation, we will likely allocate additional capital requirements during a recovery. to both share repurchases and debt repayment in the back half of 2019.
If under current market conditions we desire to pursue opportunities for growth that require additional capital, there canwe believe we would be no assurance that such capital will be available on reasonable terms, if at all.
28
Commitments and Contingencies — Asable to satisfy these needs through a combination of September 30, 2017, we maintained letters of credit in the aggregate amount of $59.5 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 September 30, 2017, no amounts had been drawn under the letters of credit.
As of September 30, 2017, we had commitments to purchase major equipment and make investments totaling approximately $191 million for our drilling, pressure pumping and oilfield rental tools 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 September 30, 2017, the remaining obligation under these agreements was approximately $86.9 million, of which approximately $345,000 and $9.5 million relates to purchases required during the remainder of 2017 and 2018, respectively. 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.
Description of Business — 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. In addition, we have other operations where we provide oilfield rental tools, 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 and pressure pumping equipment available than necessary to meet demand. As a result, drilling and pressure pumping contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods.
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 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 and pressure pumping equipment available. In circumstances of excess capacity, providers of drilling and pressure pumping services have difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict either the future level of demand for our contract drilling or pressure pumping services or future conditions in the oil and natural gas contract drilling or pressure pumping businesses.
Unconventional resource plays have substantially increased and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology drilling rigs has been hampered by their lack of capability to efficiently compete for this work. Four of the previously announced seven of APEX-XK® upgrades have been delivered and the remaining three rigs are under contract. Additionally, we also plan to upgrade two additional rigs to APEX PK™ with a box-on-box substructure and integrated walking system for enhanced performance on multi-well pads, both of which are under contract and are expected to be delivered in the first half of 2018. 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, or
construction of new technology drilling rigs.
Critical Accounting Policies
In addition to established accounting policies, our condensed consolidated financial statements are impacted by certain estimates and assumptions made by management. No changes in our critical accounting policies have occurred since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.
29
We evaluate the recoverability of our 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, our results of operations for the three month period ended September 30, 2017, and our expectations of results of operations in future periods, we concluded that no triggering event occurred during the three months ended September 30, 2017 with respect to our contract drilling segment, our pressure pumping segment or our other operations, except for oil and natural gas properties, which are discussed in the following paragraph. Our expectations of results of operations in future periods were based on the assumption that activity levels in both segments and our other operations will remain relatively stable in response to relatively stable oil prices.
We review our 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 our 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 $1.3 million in the third quarter of 2017 and $3.5 million in the nine months ended September 30, 2017 and is included in depreciation, depletion, amortization and impairment in the condensed consolidated statements of operations.
Liquidity and Capital Resources
Our liquidity as of September 30, 2017 included approximately $129 million in working capital, including $37.8 million of cash and cash equivalents, and $342 million available under our revolving credit facility. As of October 30, 2017,flows from operating activities, borrowing capacity under our revolving credit facility we had $240 million outstanding, had $4.6 million of letters of credit outstanding, and had borrowing capacity of $255 million.
On April 20, 2017, we entered into Amendment No. 4 to Credit Agreement which permitted outstanding letters of credit under the SSE credit facility to be deemed to be incurred under our credit facility and increased the amount of the accordion feature of our revolving credit facility to permit aggregate commitments to be increased to an amount not to exceed $700 million (subject to satisfaction of certain conditions and the procurement ofor additional commitments from newdebt or existing lenders). On April 20, 2017, we also entered into an agreement with certain of our lenders pursuant to which total commitments available under our revolving credit facility were $490 million through March 2019. On October 27, 2017, we entered into an additional commitment increase agreement with certain of our lenders pursuant to which total commitments available under our revolving credit facility increased to $500 million through March 2019.
On January 27, 2017, we completed an offering of 18.2 million shares of our common stock and raised net proceeds of $472 million. We used the net proceeds of the offering to repay of SSE’s outstanding indebtedness of approximately $472 million.
On October 11, 2017, we acquired all of the issued and outstanding limited liability company interests of MS Directional for $75 million in cash and approximately 8.8 million shares of our common stock.
We believe our current liquidity, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to maintain and make improvements to our existing equipment, service our debt, pay cash dividends and finance working capital requirements during a recovery. If under current market conditions we desire to pursue opportunities for growth that require additional capital,equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.
During the ninesix months ended SeptemberJune 30, 2017,2019, our sources of cash flow included:
$131 million from operating activities,
• | $365 million from operating activities, and |
$39.7 million in proceeds from the disposal of property and equipment,
$144 million in net borrowings under our revolving credit facility, and
$472 million from net proceeds from common stock issuance.
• | $31.5 million in proceeds from the disposal of property and equipment and insurance proceeds. |
During the ninesix months ended SeptemberJune 30, 2017,2019, we used $434 million for the acquisition of SSE, $11.9$16.8 million to pay dividends on our common stock, $6.8$154 million for treasurythe repurchases of our common stock and $330$215 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, oilfield rental tools and manufacturing operations, and
30
| • | 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 ninesix months ended SeptemberJune 30, 20172019 as follows:
| Per Share |
|
| Total |
| ||
|
|
|
|
| (in thousands) |
| |
Paid on March 22, 2017 | $ | 0.02 |
|
| $ | 3,326 |
|
Paid on June 22, 2017 |
| 0.02 |
|
|
| 4,269 |
|
Paid on September 21, 2017 |
| 0.02 |
|
|
| 4,271 |
|
Total cash dividends | $ | 0.06 |
|
| $ | 11,866 |
|
| Per Share |
|
| Total |
| ||
|
|
|
|
| (in thousands) |
| |
Paid on March 21, 2019 | $ | 0.04 |
|
| $ | 8,499 |
|
Paid on June 20, 2019 |
| 0.04 |
|
|
| 8,344 |
|
| $ | 0.08 |
|
| $ | 16,843 |
|
On October 25, 2017,July 24, 2019, our Board of Directors approved a cash dividend on our common stock in the amount of $0.02$0.04 per share to be paid on December 21, 2017September 19, 2019 to holders of record as of December 7, 2017.September 5, 2019. 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 purchaseauthorized purchases of up to $200 million of our common stock in open market or privately negotiated transactions. On July 25, 2018, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. On February 6, 2019, our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future share repurchases. 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 buyback program are held as treasury shares. There is no expiration date associated with the buyback program. As of SeptemberJune 30, 2017,2019, we had remaining authorization to purchase approximately $187$100 million of our outstanding common stock under the 2013 stock buyback program. Shares purchasedOn July 24, 2019, our Board of Directors approved another increase of the authorization under athe stock buyback program are accountedto allow for as treasury stock.$250 million of future share repurchases.
Treasury stock acquisitions during the ninesix months ended SeptemberJune 30, 20172019 were as follows (dollars in thousands):
| Shares |
|
| Cost |
| Shares |
|
| Cost |
| ||||
Treasury shares at beginning of period |
| 43,392,617 |
|
| $ | 911,094 |
|
| 53,701,096 |
|
| $ | 1,080,448 |
|
Purchases pursuant to stock buyback program |
| 5,503 |
|
|
| 109 |
|
| 11,745,128 |
|
|
| 150,110 |
|
Acquisitions pursuant to long-term incentive plan |
| 377,851 |
|
|
| 6,923 |
|
| 912,338 |
|
|
| 12,890 |
|
Other |
| 31,013 |
|
|
| 371 |
| |||||||
Treasury shares at end of period |
| 43,775,971 |
|
| $ | 918,126 |
|
| 66,389,575 |
|
| $ | 1,243,819 |
|
(1) | We withheld 912,338 shares during the first two quarters of 2019 with respect to the exercise price and employees’ tax withholding obligations upon the exercise of stock options and the employees’ tax withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock and restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan and not pursuant to the stock buyback program. |
2012 Credit Agreement — On SeptemberMarch 27, 2012,2018, we entered into aan 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. Bank National Association, as Co-Lead Arrangers and Joint Book Runners.
The Credit Agreement (the “BaseCredit Agreement”). The Base Credit Agreement (as amended, the “Credit Agreement”) is a committed senior unsecured revolving credit facility that includes a revolving credit facility.
On July 8, 2016, we entered into Amendment No. 2permits aggregate borrowings of up to Credit Agreement (“Amendment No. 2”), which amended the Base Credit Agreement to, among other things, make borrowing under the revolving credit facility subject to a borrowing base calculated by reference to our and certain of our subsidiaries’ eligible equipment, inventory, accounts receivable and unencumbered cash as described in Amendment No. 2. The revolving credit facility contains$600 million, including a letter of credit facility that, at any time outstanding, is limited to $50$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, in each case outstanding at any time.not to exceed total commitments of $900 million. The original maturity date under the Base Credit Agreement was September 27, 2017 for the revolving facility; however, Amendment No. 2 extended the maturity date of $357.9 million in revolving credit commitments of certain lenders to March 27, 2019.2023. On January 17, 2017,March 26, 2019, we entered into Amendment No. 31 to Amended and Restated Credit Agreement (the “Amendment”), which amended the Credit Agreement by restatingto, among other things, extend the definition of Consolidated EBITDAmaturity date under the Credit Agreement from March 27, 2023 to provide forMarch 27, 2024. We have the add-back of transaction expenses related to the SSE merger. On January 24, 2017, we entered into an agreement with certain lenders under our revolving credit facility to increase the aggregate commitments under our revolving credit facility to approximately $595.8 million,option, subject to the satisfaction of certain conditions. The aggregate commitment increase became effective on April 20, 2017 upon the consummationconditions, to exercise two one-year extensions of the SSE merger and the repayment and termination of the SSE credit facility. On April 20, 2017, we entered into Amendment No. 4 to Credit Agreement which permitted outstanding letters of credit under the SSE credit facility to be deemed to be incurred under our credit facility and increased the amount of the accordion feature of our revolving credit facility to permit aggregate commitments to be increased to an amount not to exceed $700 million (subject to satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). On April 20, 2017, we also entered into an additional commitment increase agreement with certain of our lenders pursuant to which total commitments available under our revolving credit facility (after giving effect to both commitment increases) increased to $632 million through September 2017 and to $490 million through March 2019. On October 27, 2017, we entered into an additional commitment increase agreement with certain of our lenders pursuant to which total commitments available under our revolving credit facility increased to $500 million through March 2019.maturity date.
31
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. Until September 27, 2017, theThe applicable margin on LIBOR rate loans variedvaries from 2.75%1.00% to 3.25%2.00% and the applicable margin on base rate loans variedvaries from 1.75%0.00% to 2.25%1.00%, in each case determined based upon our debt to capitalization ratio. Based on our debt to capitalization ratio at March 31, 2017, the applicable margin on LIBOR loans was 2.75% and the applicable margin on base rate loans was 1.75% as of July 1, 2017. Beginning September 27, 2017, the applicable margin on LIBOR rate loans varies from 3.25% to 3.75% and the applicable margin on base rate loans varies from 2.25% to 2.75%, in each case determined based on our excess availability under the revolving credit facility. As of September 30, 2017, the applicable margin on LIBOR rate loans was 3.25% and the applicable margin on base rate loans was 2.25%.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 for the unused portion of the revolvingvaries from 0.10% to 0.30% based on our credit facility is 0.50%.rating.
EachNone of our domestic subsidiaries unconditionally guarantees all existing and future indebtedness and liabilities of the other guarantors and us arisingare currently required to be a guarantor under the Credit Agreement, other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no material assets other than equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c)Agreement. However, if any subsidiary having total assetsguarantees or incurs debt in excess of less than $1 million. Such guarantees also cover our obligations and those of any of our subsidiaries arising under any interest rate swap contract with any person whilethe Priority Debt Basket (as defined in the Credit Agreement), such personsubsidiary is required to become a lender or an affiliate of a lender 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 compliance with two financial covenants. We must not permitthat our total debt to capitalization ratio, toexpressed as a percentage, not exceed 40%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 last dayend 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 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these covenants at September 30, 2017.
The Credit Agreement limits our ability to make investments in foreign subsidiaries or joint ventures such that, if the book value of all such investments since September 27, 2012 is above 20% of our total consolidated book value of the assets on a pro forma basis, we will not be able to make such investment. The Credit Agreement also restricts our ability to pay dividends and make equity repurchases, subject to certain exceptions, including an exception allowing such restricted payments if before and immediately after giving effect to such restricted payment, the Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) is at least 1.50 to 1.00. In addition, the Credit Agreement requires that, if our consolidated cash balance, subject to certain exclusions, is more than $100 million at the end of the day on which a borrowing is made, we can only use the proceeds from such borrowing to fund acquisitions, capital expenditures and the repurchase of indebtedness, and if such proceeds are not used in such manner within three business days, we must repay such unused proceeds on the fourth business day following such borrowings.
The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.
Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require us to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy, such acceleration is automatic), and (iii) require us to cash collateralize any outstanding letters of credit.
As of SeptemberJune 30, 2017,2019, we had $144 millionno amounts outstanding under our revolving credit facility. We had $81,000 in letters of credit outstanding under our revolving credit facility at a weighted average interest rate of 4.83%. We had $4.6 million in letters of credit outstanding at SeptemberJune 30, 20172019 and, as a result, had available borrowing capacity of $342approximately $600 million at that date. As of October 30, 2017, under our revolving credit facility we had $240 million outstanding, had $4.6 million of letters of credit outstanding, and had borrowing capacity of $255 million.
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 SeptemberJune 30, 2017,2019, we had $54.9$63.3 million in letters of credit outstanding under the Reimbursement Agreement.
32
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.
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 Septemberat June 30, 2017.2019. 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.
33
Results2028 Senior Notes —On January 19, 2018, we completed an offering of Operations$525 million aggregate principal amount of our 2028 Notes. 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 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.
We, changedat our reporting segment presentationoption, may redeem the Notes in whole or in 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 in 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 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 fourth quarterindenture.
Upon the occurrence of 2016,a change of control, as we no longer consider our oildefined 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 natural gas explorationunpaid 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 production activitiesaccrued interest, if any, on the 2028 Notes to become or to be significant to an understandingdeclared due and payable.
Commitments— As of our results. We now presentJune 30, 2019, we maintained letters of credit in the oil and natural gas exploration and production activities, oilfield rental tool business, pipe handling components and related technology business and Middle East/North Africa activities as “Other” and “Corporate” reflects only corporate activities. This change in segment presentation was applied retrospectively to all periods presented herein.
The following tables summarize operations by business segmentaggregate amount of $63.4 million primarily for the three months ended Septemberbenefit 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 June 30, 20172019, no amounts had been drawn under the letters of credit.
As of June 30, 2019, we had commitments to purchase major equipment and 2016:
Contract Drilling | 2017 |
|
| 2016 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 301,614 |
|
| $ | 123,684 |
|
|
| 143.9 | % |
Direct operating costs |
| 186,957 |
|
|
| 74,517 |
|
|
| 150.9 | % |
Margin (1) |
| 114,657 |
|
|
| 49,167 |
|
|
| 133.2 | % |
Selling, general and administrative |
| 1,451 |
|
|
| 1,301 |
|
|
| 11.5 | % |
Depreciation, amortization and impairment |
| 133,603 |
|
|
| 115,652 |
|
|
| 15.5 | % |
Operating loss | $ | (20,397 | ) |
| $ | (67,786 | ) |
|
| (69.9 | )% |
Operating days |
| 14,841 |
|
|
| 5,655 |
|
|
| 162.4 | % |
Average revenue per operating day | $ | 20.32 |
|
| $ | 21.87 |
|
|
| (7.1 | )% |
Average direct operating costs per operating day | $ | 12.60 |
|
| $ | 13.18 |
|
|
| (4.4 | )% |
Average margin per operating day (1) | $ | 7.73 |
|
| $ | 8.69 |
|
|
| (11.0 | )% |
Average rigs operating |
| 161 |
|
|
| 61 |
|
|
| 163.9 | % |
Capital expenditures | $ | 106,879 |
|
| $ | 17,551 |
|
|
| 509.0 | % |
|
|
Revenuesmake investments totaling approximately $72.8 million for our drilling, pressure pumping, directional drilling and direct operating costs increased dueoilfield rentals businesses.
Our pressure pumping business has entered into agreements to an increasepurchase minimum quantities of proppants and chemicals from certain vendors. The agreements expire in operating days. Operating days increased inyears 2019 through 2023. As of June 30, 2019, the quarter primarily dueremaining obligation under these agreements was approximately $42.2 million, of which approximately $14.9 million relates to purchases required during the remainder of 2019. In the event the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the recoveryrespective vendor for any shortfall.
Trading and Investing — We have not engaged in the oiltrading activities that include high-risk securities, such as derivatives and natural gas industrynon-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and rigs acquired in the SSE merger. Depreciation, amortization and impairment increased primarily due to the additional SSE assets. Average revenue per operating day decreased during the three months ended September 30, 2017, as compared to the three months ended September 30, 2016, due to the expiration of higher priced, legacy long-term rig contracts. Capital expenditures increased over the comparable 2016 quarter due to new rig purchases, upgrading rigs to super spec capability, higher maintenance capital expenditures and other general property and equipment upgrades. money market accounts.
Pressure Pumping | 2017 |
|
| 2016 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 362,441 |
|
| $ | 78,165 |
|
|
| 363.7 | % |
Direct operating costs |
| 290,315 |
|
|
| 77,221 |
|
|
| 276.0 | % |
Margin (1) |
| 72,126 |
|
|
| 944 |
|
| NA |
| |
Selling, general and administrative |
| 4,011 |
|
|
| 2,926 |
|
|
| 37.1 | % |
Depreciation, amortization and impairment |
| 51,274 |
|
|
| 44,587 |
|
|
| 15.0 | % |
Operating income (loss) | $ | 16,841 |
|
| $ | (46,569 | ) |
|
| (136.2 | )% |
Fracturing jobs |
| 174 |
|
|
| 84 |
|
|
| 107.1 | % |
Other jobs |
| 342 |
|
|
| 226 |
|
|
| 51.3 | % |
Total jobs |
| 516 |
|
|
| 310 |
|
|
| 66.5 | % |
Average revenue per fracturing job | $ | 2,043.61 |
|
| $ | 906.42 |
|
|
| 125.5 | % |
Average revenue per other job | $ | 20.04 |
|
| $ | 8.96 |
|
|
| 123.7 | % |
Average revenue per total job | $ | 702.41 |
|
| $ | 252.15 |
|
|
| 178.6 | % |
Average direct operating costs per total job | $ | 562.63 |
|
| $ | 249.10 |
|
|
| 125.9 | % |
Average margin per total job (1) | $ | 139.78 |
|
| $ | 3.05 |
|
| NA |
| |
Margin as a percentage of revenues (1) |
| 19.9 | % |
|
| 1.2 | % |
| NA |
| |
Capital expenditures | $ | 27,230 |
|
| $ | 8,330 |
|
|
| 226.9 | % |
|
|
34
Revenues and direct operating costs during the three months ended September 30, 2017 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 September 30, 2016. Average revenue per job increased due to improved pricing and an 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 investments to reactivate frac spreads and higher maintenance capital expenditures as a result of higher activity.
Other Operations | 2017 |
|
| 2016 |
|
| % Change |
| |||
| (in thousands) |
|
|
|
|
| |||||
Revenues | $ | 20,934 |
|
| $ | 4,284 |
|
|
| 388.7 | % |
Direct operating costs |
| 14,616 |
|
|
| 1,846 |
|
|
| 691.8 | % |
Margin (1) |
| 6,318 |
|
|
| 2,438 |
|
|
| 159.1 | % |
Selling, general and administrative |
| 3,300 |
|
|
| 354 |
|
|
| 832.2 | % |
Depreciation, depletion and impairment |
| 9,534 |
|
|
| 1,856 |
|
|
| 413.7 | % |
Operating income (loss) | $ | (6,516 | ) |
| $ | 228 |
|
| NA |
| |
Capital expenditures | $ | 8,647 |
|
| $ | 2,401 |
|
|
| 260.1 | % |
|
|
Revenues, direct operating costs, selling, general and administrative expense and depreciation expense from other operations increased primarily as a result of the inclusion of our oilfield rental tool business acquired in the SSE merger on April 20, 2017 and our pipe handling components and related technology business acquired in September 2016. Depreciation, depletion and impairment expense in 2017 includes approximately $1.3 million of oil and natural gas property impairments compared to $205,000 of oil and natural gas property impairments in 2016. The increase in capital expenditures was primarily due to investments in the oilfield rental tool business.
Corporate | 2017 |
|
| 2016 |
|
| % Change |
| |||
| (in thousands) |
|
|
|
|
| |||||
Selling, general and administrative | $ | 18,789 |
|
| $ | 12,031 |
|
|
| 56.2 | % |
Operating expense | $ | 1,266 |
|
| $ | — |
|
| NA |
| |
Merger and integration expenses | $ | 9,449 |
|
| $ | — |
|
| NA |
| |
Depreciation | $ | 2,231 |
|
| $ | 1,369 |
|
|
| 63.0 | % |
Other operating income: |
|
|
|
|
|
|
|
|
|
|
|
Net gain on asset disposals | $ | (3,712 | ) |
| $ | (2,541 | ) |
|
| 46.1 | % |
Legal settlements, net of insurance reimbursements |
| (79 | ) |
|
| (1,577 | ) |
|
| (95.0 | )% |
Other operating income | $ | (3,791 | ) |
| $ | (4,118 | ) |
|
| (7.9 | )% |
Interest income | $ | 101 |
|
| $ | 63 |
|
|
| 60.3 | % |
Interest expense | $ | 9,584 |
|
| $ | 10,244 |
|
|
| (6.4 | )% |
Other income | $ | 78 |
|
| $ | 19 |
|
|
| 310.5 | % |
Capital expenditures | $ | 305 |
|
| $ | 395 |
|
|
| (22.8 | )% |
Selling, general and administrative expense increased in the three months ended September 30, 2017 due to the expanded corporate functions as a result of the SSE acquisition. Merger and integration expenses incurred in 2017 are related to the SSE merger. Depreciation expense increased in the third quarter of 2017 compared to the same period in 2016 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. Interest expense decreased primarily due to lower debt outstanding between the two periods.
35
The following tables summarize operations by business segment for the nine months ended September 30, 2017 and 2016:
Contract Drilling | 2017 |
|
| 2016 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 730,453 |
|
| $ | 407,578 |
|
|
| 79.2 | % |
Direct operating costs |
| 475,836 |
|
|
| 219,218 |
|
|
| 117.1 | % |
Margin (1) |
| 254,617 |
|
|
| 188,360 |
|
|
| 35.2 | % |
Selling, general and administrative |
| 4,506 |
|
|
| 4,538 |
|
|
| (0.7 | )% |
Depreciation, amortization and impairment |
| 405,576 |
|
|
| 357,153 |
|
|
| 13.6 | % |
Operating loss | $ | (155,465 | ) |
| $ | (173,331 | ) |
|
| (10.3 | )% |
Operating days |
| 35,651 |
|
|
| 17,308 |
|
|
| 106.0 | % |
Average revenue per operating day | $ | 20.49 |
|
| $ | 23.55 |
|
|
| (13.0 | )% |
Average direct operating costs per operating day | $ | 13.35 |
|
| $ | 12.67 |
|
|
| 5.4 | % |
Average margin per operating day (1) | $ | 7.14 |
|
| $ | 10.88 |
|
|
| (34.4 | )% |
Average rigs operating |
| 131 |
|
|
| 63 |
|
|
| 107.9 | % |
Capital expenditures | $ | 222,426 |
|
| $ | 46,001 |
|
|
| 383.5 | % |
|
|
Revenues and direct operating costs increased primarily due to an increase in operating days. Operating days increased due to a recovery in the oil and natural gas industry and the rigs acquired in the SSE merger. Depreciation, amortization and impairment increased due to the additional SSE assets and due to a $29.0 million impairment from the write-down of drilling equipment with no continuing utility as a result of the upgrade of certain rigs to super-spec capability. Average revenue per operating day decreased during the nine months ended September 30, 2017 due to a reduction in early termination revenue and the expiration of higher priced, legacy long-term rig contracts. Early termination revenue for the nine months ended September 30, 2017 was $4.0 million, compared to $23.3 million for the same period in 2016. Average direct operating costs per operating day increased as a result of a reduction in the proportion of rigs on standby and an increase in rig reactivation expenses. Capital expenditures increased due to new rig purchases, upgrading rigs to super spec capability, higher maintenance capital expenditures and other general property and equipment upgrades.
Pressure Pumping | 2017 |
|
| 2016 |
|
| % Change |
| |||
| (dollars in thousands) |
|
|
|
|
| |||||
Revenues | $ | 793,659 |
|
| $ | 248,428 |
|
|
| 219.5 | % |
Direct operating costs |
| 643,228 |
|
|
| 234,580 |
|
|
| 174.2 | % |
Margin (1) |
| 150,431 |
|
|
| 13,848 |
|
|
| 986.3 | % |
Selling, general and administrative |
| 10,516 |
|
|
| 8,844 |
|
|
| 18.9 | % |
Depreciation, amortization and impairment |
| 141,329 |
|
|
| 141,557 |
|
|
| (0.2 | )% |
Operating loss | $ | (1,414 | ) |
| $ | (136,553 | ) |
|
| (99.0 | )% |
Fracturing jobs |
| 442 |
|
|
| 241 |
|
|
| 83.4 | % |
Other jobs |
| 962 |
|
|
| 556 |
|
|
| 73.0 | % |
Total jobs |
| 1,404 |
|
|
| 797 |
|
|
| 76.2 | % |
Average revenue per fracturing job | $ | 1,759.53 |
|
| $ | 1,005.81 |
|
|
| 74.9 | % |
Average revenue per other job | $ | 16.57 |
|
| $ | 10.84 |
|
|
| 52.9 | % |
Average revenue per total job | $ | 565.28 |
|
| $ | 311.70 |
|
|
| 81.4 | % |
Average direct operating costs per total job | $ | 458.14 |
|
| $ | 294.33 |
|
|
| 55.7 | % |
Average margin per total job (1) | $ | 107.14 |
|
| $ | 17.38 |
|
|
| 516.5 | % |
Margin as a percentage of revenues (1) |
| 19.0 | % |
|
| 5.6 | % |
|
| 239.3 | % |
Capital expenditures and acquisitions | $ | 85,423 |
|
| $ | 27,662 |
|
|
| 208.8 | % |
|
|
36
Revenues and direct operating costs during the nine months ended September 30, 2017 increased primarily due to an increase in the number and size of fracturing jobs. The total number of jobs increased as a result of the SSE merger and a recovery in the oil and natural gas industry. Margin, average margin per total job and margin as a percentage of revenues increased due to improvements in pricing and economies of scale as activity levels increased. Average revenue per job increased due to improved pricing and an increase in the size of the jobs. Average direct operating costs per total job increased due to the increase in the size of the jobs. The increase in capital expenditures was primarily due to investments to reactivate frac spreads and higher maintenance capital expenditures as a result of higher activity.
Other Operations | 2017 |
|
| 2016 |
|
| % Change |
| |||
| (in thousands) |
|
|
|
|
| |||||
Revenues | $ | 45,238 |
|
| $ | 12,973 |
|
|
| 248.7 | % |
Direct operating costs |
| 30,546 |
|
|
| 5,586 |
|
|
| 446.8 | % |
Margin (1) |
| 14,692 |
|
|
| 7,387 |
|
|
| 98.9 | % |
Selling, general and administrative |
| 7,896 |
|
|
| 1,257 |
|
|
| 528.2 | % |
Depreciation, depletion and impairment |
| 19,826 |
|
|
| 8,393 |
|
|
| 136.2 | % |
Operating loss | $ | (13,030 | ) |
| $ | (2,263 | ) |
|
| 475.8 | % |
Capital expenditures | $ | 21,016 |
|
| $ | 5,621 |
|
|
| 273.9 | % |
|
|
Revenues, direct operating costs, selling, general and administrative expense and depreciation expense from other operations increased primarily as a result of the inclusion of our oilfield rental tool business acquired in the SSE merger on April 20, 2017 and our pipe handling components and related technology business acquired in September 2016. The increase in capital expenditures was primarily due to investments in the oilfield rental tool business and in oil and natural gas working interests.
Corporate | 2017 |
|
| 2016 |
|
| % Change |
| |||
| (in thousands) |
|
|
|
|
| |||||
Selling, general and administrative | $ | 46,963 |
|
| $ | 37,032 |
|
|
| 26.8 | % |
Operating expense | $ | 1,266 |
|
| $ | — |
|
| NA |
| |
Merger and integration expenses | $ | 65,798 |
|
| $ | — |
|
| NA |
| |
Depreciation | $ | 5,456 |
|
| $ | 4,106 |
|
|
| 32.9 | % |
Other operating income: |
|
|
|
|
|
|
|
|
|
|
|
Net gain on asset disposals | $ | (19,079 | ) |
| $ | (9,808 | ) |
|
| 94.5 | % |
Legal settlements, net of insurance reimbursements |
| 578 |
|
|
| (477 | ) |
| NA |
| |
Other operating income | $ | (18,501 | ) |
| $ | (10,285 | ) |
|
| 79.9 | % |
Interest income | $ | 1,149 |
|
| $ | 273 |
|
|
| 320.9 | % |
Interest expense | $ | 26,929 |
|
| $ | 31,722 |
|
|
| (15.1 | )% |
Other income | $ | 226 |
|
| $ | 52 |
|
|
| 334.6 | % |
Selling, general and administration expense increased in the nine months ended September 30, 2017 due to the expanded corporate functions as a result of the SSE acquisition. The merger and integration expenses incurred in 2017 are related to 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 2017 period includes a gain of $11.2 million related to the sale of real estate. Interest income increased due to our investment of the proceeds from our stock offering in the first quarter of 2017 prior to utilizing those proceeds to complete the SSE merger. Interest expense decreased primarily due to lower debt outstanding between the two periods.
37
Adjusted EBITDAearnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is a supplemental financial measure not defined by accounting principles generally accepted in the United States generally accepted accounting principles, or of America (“U.S. GAAP. 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 abilityoperations from period to meetperiod and against our peers without regard to our financing methods or capital expendituresstructure. 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 workingbook values of assets, capital requirements.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 |
|
| Nine Months Ended |
| Three Months Ended |
|
| Six Months Ended |
| ||||||||||||||||||||
| September 30, |
|
| September 30, |
| June 30, |
|
| June 30, |
| ||||||||||||||||||||
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||||||
| (in thousands) |
| (in thousands) |
| ||||||||||||||||||||||||||
Net loss | $ | (33,769 | ) |
| $ | (84,143 | ) |
| $ | (189,492 | ) |
| $ | (240,512 | ) | $ | (49,447 | ) |
| $ | (10,713 | ) |
| $ | (78,061 | ) |
| $ | (45,130 | ) |
Income tax benefit |
| (13,652 | ) |
|
| (49,428 | ) |
|
| (106,953 | ) |
|
| (133,885 | ) |
| (10,128 | ) |
|
| (8,382 | ) |
|
| (16,732 | ) |
|
| (8,100 | ) |
Net interest expense |
| 9,483 |
|
|
| 10,181 |
|
|
| 25,780 |
|
|
| 31,449 |
|
| 11,542 |
|
|
| 10,307 |
|
|
| 23,494 |
|
|
| 22,509 |
|
Depreciation, depletion, amortization and impairment |
| 196,642 |
|
|
| 163,464 |
|
|
| 572,187 |
|
|
| 511,209 |
|
| 208,688 |
|
|
| 212,384 |
|
|
| 423,098 |
|
|
| 422,276 |
|
Adjusted EBITDA | $ | 158,704 |
|
| $ | 40,074 |
|
| $ | 301,522 |
|
| $ | 168,261 |
| $ | 160,655 |
|
| $ | 203,596 |
|
| $ | 351,799 |
|
| $ | 391,555 |
|
Income TaxesCritical Accounting Policies
Our effective income tax rateIn February 2016, the FASB issued an accounting standard update to provide guidance for the three months ended September 30, 2017 was 28.8%, comparedaccounting for leasing transactions. The standard requires the lessee to recognize a lease liability along with 37.0%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 three months ended September 30, 2016. Forlease liability and related right-of-use asset for leases with a term of one year or less. We adopted this new leasing guidance effective January 1, 2019 utilizing the nine months ended September 30, 2017, the effective income tax rate was 36.1%, comparedmodified retrospective approach. See Note 4 to 35.8%our unaudited condensed consolidated financial statements for the nine months ended September 30, 2016. The effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, changes in pretax income in countries with varying statutory tax rates, impactadditional details of stateour adoption.
In addition to established accounting policies, our condensed consolidated financial statements are impacted by certain estimates and local taxes, and other differences related to the recognition of income and expense between U.S. GAAP and tax. assumptions made by management.
Compared with the third quarter of 2016, the lower effective tax rate for the third quarter of 2017 was primarily related to the impact of share-based payment transactions and non-deductible transaction costs associated with the SSE merger, as well as true-up adjustments of U.S. taxes for tax return filings during the third quarter of 2017.
Recently Issued Accounting Standards
Please seeSee Note 141 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 of West Texas Intermediate 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 substantially from the lows experienced in the first quarter of 2016. DuringOil prices reached a high of $77.41 in June 2018. Oil prices remain volatile, as the closing price of oil reached a fourth quarter 2018 high of 2016,$76.40 per barrel on October 3, 2018, before declining by 42% over the Organizationcourse of Petroleum Exporting Countries (“OPEC”) and certain non-OPEC countries, including Russia, announced an agreementthree months to cut oil production, resultingreach a low of $44.48 per barrel in an increase in oil prices.late December 2018. Oil prices averaged $48.14$59.88 per barrel in the thirdsecond quarter of 2017. 2019 and closed at $55.87 on July 22, 2019. U.S. rig counts increased in response to improved oil prices in early 2018. Despite oil prices in the mid-$50s to low-$60s, drilling and pressure pumping activity has recently declined, largely as a result of reduced customer spending.
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.
38
ITEMITEM 3. Quantitative and Qualitative Disclosures About Market Risk
As of SeptemberJune 30, 2017,2019, we would have 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. Until September 27, 2017, theThe applicable margin on LIBOR rate loans variedvaries from 2.75%1.00% to 3.25%2.00% and the applicable margin on base rate loans varies from 1.75%0.00% to 2.25%, in each case determined based upon our debt to capitalization ratio. Beginning September 27, 2017, the applicable margin on LIBOR rate loans varies from 3.25% to 3.75% and the applicable margin on base rate loans varies from 2.25% to 2.75%1.00%, in each case determined based on our excess availability under the revolving credit facility.rating. As of SeptemberJune 30, 2017,2019, the applicable margin on LIBOR rate loans was 3.25%1.5% and the applicable margin on base rate loans was 2.25%0.5%.
As of SeptemberJune 30, 2017,2019, we had $144 millionno amounts outstanding under our revolving credit facility at a weighted average interest rate of 4.83%. facility. The interest rate on the borrowings outstanding under our revolving credit facility is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate.
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 SeptemberJune 30, 2017,2019, 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 financial condition or results of operations or financial condition.operations.
The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.
ITEM 4. Controls and Procedures
Disclosure Controls and Procedures — We maintain disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act), designed to ensure that the information required to be disclosed in the reports that we file with the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.
Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10‑Q. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of SeptemberJune 30, 2017.2019.
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 SSE on April 20, 2017 and MS Directional on October 11, 2017, and we are integrating each of SSE and 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
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 EPA, OSHA and the CSB initiated investigations related to this accident. We have cooperated with each of these agencies during its investigation. Our last communication with the EPA was in February 2018. On June 12, 2019, the CSB released its investigation report and issued 19 operational-related recommendations to eight different parties, including five recommendations to us.
On July 18, 2018, OSHA issued a citation containing alleged violations, proposed abatement dates and an aggregate proposed penalty of approximately $74,000. We have filed a notice of contest with OSHA that contests all citation items, abatement dates and proposed penalties. The Department of Labor filed a complaint on OSHA’s behalf seeking enforcement of the citation as issued. We have filed an answer to the complaint and are litigating our contest of the citation items. The ultimate resolution of the OSHA citation items is not known at this time, and we are unable to determine what alleged violations and proposed penalties will be modified or eliminated, if any.
Lawsuits have been filed in the District Court for Pittsburg County, Oklahoma in connection with the five individuals who lost their lives and one of our employees who was injured in the accident. The lawsuits were consolidated for discovery purposes under Cause No. CJ-2018-60 (the “Litigation”). We have finalized settlement agreements with each of the plaintiffs who brought wrongful death lawsuits, and we have been dismissed from those lawsuits. The remaining lawsuit by our surviving employee alleges various causes of action against us including negligence, negligence per se, gross negligence and intentional conduct, and the plaintiff seeks an unspecified amount of damages, including punitive or exemplary damages, costs, interest, and other relief. We dispute the plaintiff’s allegations against us and intend to continue 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 the Litigation. 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; webusiness.
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.
The Loss of Large Customers Could Have a Material Adverse Effect on Our Financial Condition and Results of Operations.
With respect to our consolidated operating revenues in 2016, we received approximately 51% from our ten largest customers, 33% from our five largest customers and 14% from our largest customer. For the three months ended March 31, 2017, the five months ended December 31, 2016, the seven months ended July 31, 2016, and the years ended December 31, 2015, 2014 and 2013, Chesapeake Energy Corporation (“CHK”) and its working interest partners accounted for approximately 53%, 51%, 65%, 70%, 81% and 90% of SSE’s revenues, respectively. For the three and nine months ended September 30, 2017, CHK and its working interest partners accounted for approximately 7% and 14% of the pro forma combined revenues of SSE and Patterson-UTI, respectively. We are indirectly subject to the business and financial risks of our customers and could be materially adversely affected by the impact of these risks on our largest customers. The loss of, reduction in business from, or failure to receive payment from, one or more of our largest customers could have a material adverse effect on our business, financial condition, cash flows and results of operations.
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 SeptemberJune 30, 2017.2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 (2) |
|
| Share |
|
| or Programs |
|
| thousands)(1) |
| ||||
July 2017 |
|
| 13,162 |
|
| $ | 20.00 |
|
|
| — |
|
|
| 186,544 |
|
August 2017 |
|
| 156,675 |
|
| $ | 15.60 |
|
|
| — |
|
|
| 186,544 |
|
September 2017 |
|
| 20,314 |
|
| $ | 18.45 |
|
|
| — |
|
|
| 186,544 |
|
Total |
|
| 190,151 |
|
|
|
|
|
|
| — |
|
|
| 186,544 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 (1) |
|
| Share |
|
| or Programs |
|
| thousands)(2) |
| ||||
April 2019 |
|
| 808,534 |
|
| $ | 14.54 |
|
|
| — |
|
| $ | 174,890 |
|
May 2019 |
|
| — |
|
| $ | — |
|
|
| — |
|
| $ | 174,890 |
|
June 2019 |
|
| 6,471,573 |
|
| $ | 11.82 |
|
|
| 6,336,996 |
|
| $ | 99,890 |
|
Total |
|
| 7,280,107 |
|
|
|
|
|
|
| 6,336,996 |
|
| $ | 99,890 |
|
|
(1) | We withheld 912,098 shares in the second quarter with respect to the exercise price and employees’ tax withholding obligations upon the exercise of stock options and the employees’ tax withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock and restricted stock units. These shares were acquired at fair market value pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan and not pursuant to the stock buyback program. |
(2) | 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. |
|
|
40
The following exhibits are filed herewith or incorporated by reference, as indicated:
3.1 |
| |
|
|
|
3.2 |
| |
|
|
|
3.3 |
| |
3.4 | ||
3.5 | ||
|
|
|
10.1 |
| |
| ||
| ||
|
|
|
31.1* |
| |
|
|
|
31.2* |
| |
|
|
|
32.1* |
| |
|
|
|
|
|
|
101.SCH* | XBRL Taxonomy Extension Schema Document | |
101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB* | XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document | |
* | filed herewith |
41
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: November 2, 2017July 29, 2019
42
44