Attached files
| file | filename |
|---|---|
| EX-32.2 - EXHIBIT 32.2 - C&J Energy Services, Inc. | cjes33118ex322.htm |
| EX-32.1 - EXHIBIT 32.1 - C&J Energy Services, Inc. | cjes33118ex321.htm |
| EX-31.2 - EXHIBIT 31.2 - C&J Energy Services, Inc. | cjes33118ex312.htm |
| EX-31.1 - EXHIBIT 31.1 - C&J Energy Services, Inc. | cjes33118ex311.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2018
or
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 000-55404
C&J Energy Services, Inc.
(Exact name of registrant as specified in its charter)
Delaware | 81-4808566 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
3990 Rogerdale Rd.
Houston, Texas 77042
(Address of principal executive office)
(713) 325-6000
(Registrant’s telephone number, including area code)
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 ý No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 | ý | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ | |||
Emerging growth company | ¨ | |||||
If an emerging growth company, indicated 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 ý
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ý No ¨
The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at May 4, 2018, was 68,399,099.
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
Page | ||
Consolidated Statements of Operations for the three months ended March 31, 2018 and 2017 (Successor) and on January 1, 2017 (Predecessor) | ||
Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2018 and 2017 (Successor) and on January 1, 2017 (Predecessor) | ||
-i-
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
March 31, 2018 | December 31, 2017 | |||||||
(Unaudited) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 87,977 | $ | 113,887 | ||||
Accounts receivable, net of allowance of $4,919 at March 31, 2018 and $4,269 at December 31, 2017 | 391,149 | 367,906 | ||||||
Inventories, net | 83,920 | 77,793 | ||||||
Prepaid and other current assets | 23,169 | 33,011 | ||||||
Total current assets | 586,215 | 592,597 | ||||||
Property, plant and equipment, net of accumulated depreciation of $178,054 at March 31, 2018 and $133,755 at December 31, 2017 | 723,780 | 703,029 | ||||||
Other assets: | ||||||||
Goodwill | 147,515 | 147,515 | ||||||
Intangible assets, net | 121,632 | 123,837 | ||||||
Deferred financing costs, net of accumulated amortization of $754 at March 31, 2018 and $608 at December 31, 2017 | 3,315 | 3,379 | ||||||
Other noncurrent assets | 23,880 | 38,500 | ||||||
Total assets | $ | 1,606,337 | $ | 1,608,857 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 157,059 | $ | 138,624 | ||||
Payroll and related costs | 35,830 | 52,812 | ||||||
Accrued expenses | 49,457 | 66,547 | ||||||
Other current liabilities | 939 | 867 | ||||||
Total current liabilities | 243,285 | 258,850 | ||||||
Deferred tax liabilities | 4,280 | 3,917 | ||||||
Other long-term liabilities | 25,945 | 24,668 | ||||||
Total liabilities | 273,510 | 287,435 | ||||||
Commitments and contingencies | ||||||||
Stockholders' equity | ||||||||
Common stock, par value of $0.01, 1,000,000,000 shares authorized, 68,433,387 issued and outstanding at March 31, 2018 and 68,546,820 issued and outstanding at December 31, 2017 | 684 | 686 | ||||||
Additional paid-in capital | 1,303,202 | 1,298,859 | ||||||
Accumulated other comprehensive loss | (950 | ) | (580 | ) | ||||
Retained earnings | 29,891 | 22,457 | ||||||
Total stockholders' equity | 1,332,827 | 1,321,422 | ||||||
Total liabilities and stockholders’ equity | $ | 1,606,337 | $ | 1,608,857 | ||||
See accompanying notes to consolidated financial statements
-1-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
Successor | Predecessor | |||||||||||
Three Months Ended March 31, 2018 | Three Months Ended March 31, 2017 | On January 1, 2017 | ||||||||||
(Unaudited) | ||||||||||||
Revenue | $ | 553,000 | $ | 314,194 | $ | — | ||||||
Costs and expenses: | ||||||||||||
Direct costs | 418,997 | 261,743 | — | |||||||||
Selling, general and administrative expenses | 65,935 | 62,092 | — | |||||||||
Research and development | 1,872 | 1,217 | — | |||||||||
Depreciation and amortization | 46,343 | 31,606 | — | |||||||||
Gain on disposal of assets | (489 | ) | (6,056 | ) | — | |||||||
Operating income (loss) | 20,342 | (36,408 | ) | — | ||||||||
Other income (expense): | ||||||||||||
Interest expense, net | (428 | ) | (691 | ) | — | |||||||
Other income (expense), net | 620 | 1,562 | — | |||||||||
Total other income (expense) | 192 | 871 | — | |||||||||
Income (loss) before reorganization items and income taxes | 20,534 | (35,537 | ) | — | ||||||||
Reorganization items | — | — | (293,969 | ) | ||||||||
Income tax benefit | (60 | ) | (3,236 | ) | (4,613 | ) | ||||||
Net income (loss) | $ | 20,594 | $ | (32,301 | ) | $ | 298,582 | |||||
Net income (loss) per common share: | ||||||||||||
Basic | $ | 0.31 | $ | (0.58 | ) | $ | 2.52 | |||||
Diluted | $ | 0.31 | $ | (0.58 | ) | $ | 2.52 | |||||
Weighted average common shares outstanding: | ||||||||||||
Basic | 67,186 | 55,557 | 118,633 | |||||||||
Diluted | 67,266 | 55,557 | 118,633 | |||||||||
See accompanying notes to consolidated financial statements
-2-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
Successor | Predecessor | |||||||||||
Three Months Ended March 31, 2018 | Three Months Ended March 31, 2017 | On January 1, 2017 | ||||||||||
(Unaudited) | ||||||||||||
Net income (loss) | $ | 20,594 | $ | (32,301 | ) | $ | 298,582 | |||||
Other comprehensive income (loss): | ||||||||||||
Foreign currency translation loss, net of tax | (370 | ) | (712 | ) | — | |||||||
Comprehensive income (loss) | $ | 20,224 | $ | (33,013 | ) | $ | 298,582 | |||||
See accompanying notes to consolidated financial statements
-3-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(In thousands)
Common Stock | Additional Paid-in Capital | Other Comprehensive Loss | Retained Earnings (Deficit) | Total | |||||||||||||||||||
Number of Shares | Amount, at $0.01 par value | ||||||||||||||||||||||
Balance, December 31, 2016 (Predecessor) | 119,530 | 1,195 | 1,009,426 | (2,600 | ) | (1,306,591 | ) | (298,570 | ) | ||||||||||||||
Cancellation of Predecessor equity | (119,530 | ) | (1,195 | ) | (1,009,426 | ) | 2,600 | 1,306,591 | 298,570 | ||||||||||||||
Issuance of New Equity and New Warrants | 40,000 | 400 | 725,464 | — | — | 725,864 | |||||||||||||||||
Rights Offering | 15,464 | 155 | 199,845 | — | — | 200,000 | |||||||||||||||||
Balance, January 1, 2017 (Successor) | 55,464 | 555 | 925,309 | — | — | 925,864 | |||||||||||||||||
Public offering of common stock, net of offering costs | 7,050 | 71 | 215,849 | — | — | 215,920 | |||||||||||||||||
Issuance of stock for business acquisition | 4,420 | 44 | 138,122 | — | — | 138,166 | |||||||||||||||||
Issuance of restricted stock, net of forfeitures | 1,718 | 17 | (17 | ) | — | — | — | ||||||||||||||||
Exercise of warrants | 2 | — | — | — | — | — | |||||||||||||||||
Employee tax withholding on restricted stock vesting | (107 | ) | (1 | ) | (3,841 | ) | — | — | (3,842 | ) | |||||||||||||
Share-based compensation | — | — | 23,437 | — | — | 23,437 | |||||||||||||||||
Net income | — | — | — | — | 22,457 | 22,457 | |||||||||||||||||
Foreign currency translation loss, net of tax | — | — | — | (580 | ) | — | (580 | ) | |||||||||||||||
Balance, December 31, 2017 (Successor) | 68,547 | $ | 686 | $ | 1,298,859 | $ | (580 | ) | $ | 22,457 | $ | 1,321,422 | |||||||||||
Cumulative effect from change in accounting principle | — | — | — | — | (13,160 | ) | (13,160 | ) | |||||||||||||||
Issuance of restricted stock, net of forfeitures | (35 | ) | (1 | ) | 1 | — | — | — | |||||||||||||||
Employee tax withholding on restricted stock vesting | (79 | ) | (1 | ) | (2,184 | ) | — | — | (2,185 | ) | |||||||||||||
Share-based compensation | — | — | 6,526 | — | — | 6,526 | |||||||||||||||||
Net income | — | — | — | — | 20,594 | 20,594 | |||||||||||||||||
Foreign currency translation loss, net of tax | — | — | — | (370 | ) | — | (370 | ) | |||||||||||||||
Balance, March 31, 2018 (Successor) * | 68,433 | 684 | 1,303,202 | (950 | ) | 29,891 | 1,332,827 | ||||||||||||||||
* | Unaudited |
See accompanying notes to consolidated financial statements
-4-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Successor | Predecessor | ||||||||||||
Three Months Ended March 31, 2018 | Three Months Ended March 31, 2017 | On January 1, 2017 | |||||||||||
(Unaudited) | |||||||||||||
Cash flows from operating activities: | |||||||||||||
Net income (loss) | $ | 20,594 | $ | (32,301 | ) | $ | 298,582 | ||||||
Adjustments to reconcile net income (loss) to net cash used in operating activities: | |||||||||||||
Depreciation and amortization | 46,343 | 31,606 | — | ||||||||||
Deferred income taxes | — | — | (4,613 | ) | |||||||||
Provision for doubtful accounts | 1,261 | 576 | — | ||||||||||
Equity (earnings) loss from unconsolidated affiliate | (50 | ) | 182 | — | |||||||||
Gain on disposal of assets | (489 | ) | (6,056 | ) | — | ||||||||
Share-based compensation expense | 6,526 | 16,882 | — | ||||||||||
Amortization of deferred financing costs | 147 | 153 | — | ||||||||||
Reorganization items, net | — | — | (315,626 | ) | |||||||||
Changes in operating assets and liabilities: | |||||||||||||
Accounts receivable | (25,683 | ) | (94,514 | ) | — | ||||||||
Inventories | (6,184 | ) | (5,006 | ) | — | ||||||||
Prepaid expenses and other current assets | 4,446 | 5,675 | — | ||||||||||
Accounts payable | 16,088 | 8,525 | — | ||||||||||
Payroll related costs and accrued expenses | (31,459 | ) | (594 | ) | (1,436 | ) | |||||||
Liabilities subject to compromise | — | — | (33,000 | ) | |||||||||
Income taxes receivable (payable) | 3,637 | (2,694 | ) | — | |||||||||
Other | 479 | (336 | ) | — | |||||||||
Net cash provided by (used in) operating activities | 35,656 | (77,902 | ) | (56,093 | ) | ||||||||
Cash flows from investing activities: | |||||||||||||
Purchases of and deposits on property, plant and equipment | (63,028 | ) | (11,585 | ) | — | ||||||||
Proceeds from disposal of property, plant and equipment and non-core service lines | 3,641 | 28,200 | — | ||||||||||
Net cash provided by (used in) investing activities | (59,387 | ) | 16,615 | — | |||||||||
Cash flows from financing activities: | |||||||||||||
Payments on DIP Facility | — | — | (25,000 | ) | |||||||||
Financing costs | (82 | ) | (206 | ) | (2,248 | ) | |||||||
Proceeds from issuance of common stock from rights offering | — | — | 200,000 | ||||||||||
Employee tax withholding on restricted stock vesting | (2,185 | ) | (3,773 | ) | — | ||||||||
Net cash provided by (used in) financing activities | (2,267 | ) | (3,979 | ) | 172,752 | ||||||||
Effect of exchange rate changes on cash | 88 | (858 | ) | — | |||||||||
Net increase (decrease) in cash and cash equivalents | (25,910 | ) | (66,124 | ) | 116,659 | ||||||||
Cash and cash equivalents, beginning of period | 113,887 | 181,242 | 64,583 | ||||||||||
Cash and cash equivalents, end of period | $ | 87,977 | $ | 115,118 | $ | 181,242 | |||||||
See accompanying notes to consolidated financial statements
-5-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 - Organization, Nature of Business and Summary of Significant Accounting Policies
Organization and Nature of Business
C&J Energy Services, Inc., a Delaware corporation (the “Successor” and together with its consolidated subsidiaries for periods subsequent to the Plan Effective Date (as defined in Note 2 - Chapter 11 Proceeding and Emergence), “C&J” or the “Company”), is a leading provider of well construction and intervention, well completion, well support and other complementary oilfield services and technologies to oil and gas exploration and production (“E&P”) companies throughout the continental United States. The Company is a completions-focused service provider offering a diverse, integrated suite of services across the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, rig services, fluids management and other completion and specialty well site support services. The Company is headquartered in Houston, Texas, and operates in all active onshore basins in the continental United States.
The Company was founded in Texas in 1997. On April 12, 2017, following the successful completion of a financial restructuring (see Note 2 - Chapter 11 Proceeding and Emergence), the Company completed an underwritten public offering of common stock and began trading on the New York Stock Exchange (“NYSE”) under the symbol “CJ.”
Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation. The accompanying consolidated financial statements have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2017, the consolidated statements of operations, comprehensive income (loss), and cash flows on January 1, 2017, and the consolidated statement of changes in stockholders' equity as of December 31, 2016, January 1, 2017 and December 31, 2017, are derived from audited consolidated financial statements. In the opinion of management, all material adjustments, consisting of normal recurring adjustments, necessary for fair presentation have been included. These consolidated financial statements include all accounts of the Company. All significant intercompany transactions and accounts have been eliminated upon consolidation.
These consolidated financial statements have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”) for interim financial information. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“U.S. GAAP”) for complete financial statements. Therefore, these consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto for the fiscal year ended December 31, 2017, which are included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017 filed with the SEC. The operating results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the full year.
On January 1, 2017 (the "Fresh Start Reporting Date"), in connection with the Company's emergence from its Chapter 11 Proceeding (as defined in Note 2 - Chapter 11 Proceeding and Emergence), the Company applied the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852 - Reorganizations, in preparing the consolidated financial statements. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the Chapter 11 Proceeding from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that were realized or incurred in the Chapter 11 Proceeding were recorded in a reorganization line item on the consolidated statements of operations. The Company's consolidated financial statements and notes on January 1, 2017, are not comparable to the consolidated financial statements for the periods subsequent to January 1, 2017, due to the application of fresh start accounting as described above.
Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Estimates are used in, but are not limited to, determining the following: allowance for doubtful accounts, valuation of long-lived assets and intangibles, goodwill, useful lives used in depreciation and amortization, inventory reserves, income taxes and share-based compensation. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, or as additional information is obtained and as the Company’s operating environment changes.
-6-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Cash and Cash Equivalents. For purposes of the consolidated statement of cash flows, cash is defined as cash on-hand, demand deposits and short-term investments with initial maturities of three months or less. The Company maintains its cash and cash equivalents in various financial institutions, which at times may exceed federally insured amounts. Management believes that this risk is not significant. Cash balances related to the Company's captive insurance subsidiaries, which totaled $11.2 million and $23.8 million at March 31, 2018 and December 31, 2017, respectively, are included in cash and cash equivalents in the consolidated balance sheets, and the Company expects to use these cash balances to fund the operations of the captive insurance subsidiaries and to settle future anticipated claims.
Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are generally stated at the amount billed to customers. The Company provides an allowance for doubtful accounts, which is based upon a review of outstanding receivables, historical collection information and existing economic conditions. Provisions for doubtful accounts are recorded when it is deemed probable that the customer will not make the required payments at either the contractual due dates or in the future.
Inventories. Inventories are carried at the lower of cost or net realizable value using a weighted average cost flow method. Inventories for the Company consist of raw materials, work-in-process and finished goods, including equipment components, chemicals, proppants, supplies and materials for the Company's operations.
Inventories consisted of the following (in thousands):
March 31, 2018 | December 31, 2017 | |||||||
Raw materials | $ | 4,173 | $ | 5,302 | ||||
Work-in-process | 1,877 | 1,329 | ||||||
Finished goods | 80,767 | 74,552 | ||||||
Total inventory | 86,817 | 81,183 | ||||||
Inventory reserve | (2,897 | ) | (3,390 | ) | ||||
Inventory, net | $ | 83,920 | $ | 77,793 | ||||
Property, Plant and Equipment. Property, plant and equipment ("PP&E") are reported at cost less accumulated depreciation. Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to expense when incurred. Refurbishments are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operating income.
PP&E are evaluated on a quarterly basis to identify events or changes in circumstances (“triggering events”) that indicate the carrying value of certain PP&E may not be recoverable. PP&E are reviewed for impairment upon the occurrence of a triggering event. An impairment loss is recorded in the period in which it is determined that the carrying amount of PP&E is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets with such cash flows to be realized over the estimated remaining useful life of the primary asset within the asset group, excluding interest expense. The Company determined the lowest level of identifiable cash flows that are independent of other asset groups to be primarily at the service line level. The Company's assets groups consist of the well support services, fracturing, cased-hole wireline and pumping services, well construction and intervention, artificial lift applications, and data acquisition and control instruments provider service lines as well as the research and technology ("R&T") service lines. If the estimated undiscounted future net cash flows for a given asset group is less than the carrying amount of the related assets, an impairment loss is determined by comparing the estimated fair value with the carrying value of the related assets. The impairment loss is then allocated across the asset group's major classifications. No impairment charge was recorded for the three months ended March 31, 2018 and 2017.
Goodwill and Definite-Lived Intangible Assets. Goodwill may be allocated across three reporting units: Completion Services, Well Construction and Intervention Services, and Well Support Services. At the reporting unit level, the Company tests goodwill for impairment on an annual basis as of October 31 of each year, or when events or changes in circumstances, referred to as triggering events, indicate the carrying value of goodwill may not be recoverable and that a potential impairment exists.
-7-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Judgment is used in assessing whether goodwill should be tested for impairment more frequently than annually. Factors such as unexpected adverse economic conditions, competition, market changes and other external events may require more frequent assessments. See Note 4 - Goodwill and Other Intangible Assets for further discussion on impairment testing results.
Before employing quantitative impairment testing methodologies, the Company may first evaluate the likelihood of impairment by considering qualitative factors relevant to each reporting unit, such as macroeconomic, industry, market or any other factors that have a significant bearing on fair value. If the Company first utilizes a qualitative approach and determines that it is more likely than not that goodwill is impaired, quantitative testing methodologies are then applied. Otherwise, the Company concludes that no impairment has occurred. Quantitative impairment testing involves comparing the fair value of each reporting unit to its carrying value, including goodwill. Fair value reflects the price a market participant would be willing to pay in a potential sale of the reporting unit. If the fair value exceeds carrying value, then it is concluded that no goodwill impairment has occurred. If the carrying value of the reporting unit exceeds its fair value an impairment loss is recognized in an amount equal to the excess, not to exceed the amount of goodwill allocated to the reporting unit.
The Company’s impairment analysis involves the use of a blended income and market approach. Significant management judgment is necessary to evaluate the impact of operating and macroeconomic changes on each reporting unit. Critical assumptions include projected revenue growth, fleet count, utilization, gross profit rates, sales, general and administrative ("SG&A") rates, working capital fluctuations, capital expenditures, discount rates, terminal growth rates, and price-to-earnings multiples. The Company’s market capitalization is also used to corroborate reporting unit valuations.
Definite-lived intangible assets are amortized over their estimated useful lives. With the exception of the C&J trade name, these intangibles, along with PP&E, are reviewed for impairment when a triggering event indicates that the asset group may have a net book value in excess of recoverable value. In these cases, the Company performs a recoverability test on its PP&E and definite-lived intangible assets by comparing the estimated future net undiscounted cash flows expected to be generated from the use of these assets to the carrying amount of the assets for recoverability. If the estimated undiscounted cash flows exceed the carrying amount of the assets, an impairment does not exist, and a loss will not be recognized. If the undiscounted cash flows are less than the carrying amount of the assets, the assets are not recoverable and the amount of impairment must be determined by fair valuing the assets. The C&J trade name is a corporate asset and is reviewed for impairment upon the occurrence of a triggering event by comparing the carrying amount of the corporate assets with the remaining cash flows available from the lower-level asset groups that benefit from the asset.
Deferred Financing Costs. Costs incurred to obtain term debt financing are presented on the balance sheet as a direct deduction from the carrying amount of the term debt, consistent with debt discounts, and accreted over the term of the loan using the effective interest method. Costs incurred to obtain revolver based financing are capitalized and amortized over the term of the loan using the effective interest method.
Revenue Recognition. The Company adopted Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers and its related updates as codified under ASC 606, Revenue from Contracts with Customers ("ASC 606") on January 1, 2018, using the modified retrospective method for all contracts not completed as of the date of adoption. The reported results for the three months ended March 31, 2018, reflect the application of ASC 606 guidance while the reported results for the corresponding prior year period were prepared under the previous guidance of ASC No. 605, Revenue Recognition ("ASC 605").
The adoption of ASC 606 represents a change in accounting principle that will more closely align revenue recognition with the performance of the Company's services and will provide financial statement readers with enhanced disclosures. In accordance with ASC 606, revenue is recognized in a manner reflecting the transfer of goods or services to customers based on consideration a company expects to receive. The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product or service to a customer. To achieve this core principle, ASC 606 requires the Company to apply the following five steps: (1) identify the contract with a customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to performance obligations in the contract, and (5) recognize revenue when or as the Company satisfies a performance obligation. The five-step model requires management to exercise judgment when evaluating contracts and recognize revenue.
The Company’s services create or enhance a customer controlled asset. The performance obligations of each of the Company’s services lines are primarily satisfied over time. Measurement of the satisfaction of the performance obligations is measured using the output method, which is typically evidenced by a field ticket. A field ticket includes items such as services
-8-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
performed, consumables used, and man hours incurred to complete the job for the customer. Each field ticket evidences the work that was performed at the job site and is used to invoice customers. Payment terms for invoices issued are in accordance with the master services agreement with each customer, which typically require payment within 30 days of the invoice issuance.
A portion of the Company’s contracts contain variable consideration; however, this variable consideration is typically unknown at the time of contract inception, and is not known until the job is complete, at which time the variability is resolved. Examples of variable consideration include the number of hours that will be incurred and the amount of consumables (such as fluids and proppants) that will be used to complete a job.
In the course of providing services to its customers, the Company may use consumables; for example, in the Company’s fracturing business, sand, guar and chemicals are used in the fracturing service for the customer. ASC 606 requires that goods or services promised to a customer be identified separately when they are distinct within the contract. However, the consumables are used to complete the service for the customer and are not beneficial to the customer on their own. As such, the consumables are not a separate performance obligation, but instead are combined with the other services within the context of the contract and accounted for as a single performance obligation.
Disaggregation of Revenue
In the following table, revenue is disaggregated by the Company’s core service lines and geography. The table also includes a reconciliation of the disaggregated revenue with the Company’s reportable segments.
Three Months Ended March 31, 2018 | ||||||||||||||||
Completion Services | Well Construction and Intervention Services | Well Support Services | Total | |||||||||||||
Product Service Line | ||||||||||||||||
Fracturing | $ | 269,491 | $ | — | $ | — | $ | 269,491 | ||||||||
Cased-hole Wireline & Pumping | 99,754 | — | — | 99,754 | ||||||||||||
Cementing | — | 61,548 | — | 61,548 | ||||||||||||
Coiled Tubing | — | 25,788 | — | 25,788 | ||||||||||||
Rig Services | — | — | 48,445 | 48,445 | ||||||||||||
Fluids Management | — | — | 31,795 | 31,795 | ||||||||||||
Other | 4,900 | 81 | 11,198 | 16,179 | ||||||||||||
$ | 374,145 | $ | 87,417 | $ | 91,438 | $ | 553,000 | |||||||||
Geography | ||||||||||||||||
West Texas | $ | 178,975 | $ | 48,779 | $ | 23,822 | $ | 251,576 | ||||||||
South Texas / South East | 99,184 | 12,683 | 8,777 | 120,644 | ||||||||||||
Rockies / Bakken | 39,009 | 4,982 | 9,933 | 53,924 | ||||||||||||
California | 5,048 | — | 39,830 | 44,878 | ||||||||||||
Mid-Con | 35,620 | 10,180 | 7,829 | 53,629 | ||||||||||||
North East | 15,036 | 10,793 | 621 | 26,450 | ||||||||||||
International | 1,273 | — | 626 | 1,899 | ||||||||||||
$ | 374,145 | $ | 87,417 | $ | 91,438 | $ | 553,000 | |||||||||
-9-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Three Months Ended March 31, 2017 | ||||||||||||||||
Completion Services | Well Construction and Intervention Services | Well Support Services | Total | |||||||||||||
Product Service Line | ||||||||||||||||
Fracturing | $ | 130,663 | $ | — | $ | — | $ | 130,663 | ||||||||
Cased-hole Wireline & Pumping | 56,265 | — | — | 56,265 | ||||||||||||
Cementing | — | 7,503 | — | 7,503 | ||||||||||||
Coiled Tubing | — | 17,758 | — | 17,758 | ||||||||||||
Rig Services | — | — | 55,545 | 55,545 | ||||||||||||
Fluids Management | — | — | 29,934 | 29,934 | ||||||||||||
Other | 4,881 | 858 | 10,787 | 16,526 | ||||||||||||
$ | 191,809 | $ | 26,119 | $ | 96,266 | $ | 314,194 | |||||||||
Geography | ||||||||||||||||
West Texas | $ | 85,578 | $ | 8,406 | $ | 19,487 | $ | 113,471 | ||||||||
South Texas / South East | 38,276 | 10,148 | 12,402 | 60,826 | ||||||||||||
Rockies / Bakken | 33,969 | — | 8,980 | 42,949 | ||||||||||||
California | 2,716 | — | 34,566 | 37,282 | ||||||||||||
Mid-Con | 16,714 | 2,126 | 6,152 | 24,992 | ||||||||||||
North East | 13,656 | 5,439 | 2,125 | 21,220 | ||||||||||||
International | 900 | — | 12,554 | 13,454 | ||||||||||||
$ | 191,809 | $ | 26,119 | $ | 96,266 | $ | 314,194 | |||||||||
The following is a description of the Company’s core service lines - separated by reportable segments - from which the Company generates its revenue. For more detailed information about reportable segments, see Note 7 - Segment Information.
Completion Services Segment
Fracturing Services Revenue. Through its fracturing service line, the Company provides fracturing services under term contracts that include either pricing agreements or “take-or-pay” provisions or on a spot market basis. Revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or more fracturing stages. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the services performed and the consumables (such as fluids and proppants) used during the course of service. The field ticket may also include charges for the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables.
Pursuant to pricing agreements and other contractual arrangements that the Company may enter into from time to time, such as those associated with an award from a bid process, customers typically commit to targeted utilization levels based on a specified number of hours of service at agreed-upon pricing, but without termination penalties or obligations to pay for services not used by the customer. In addition, the agreed-upon pricing is typically subject to periodic review, as specifically defined in the agreement, and may be adjusted upon the agreement of both parties.
Under term contracts with “take-or-pay” provisions, the Company’s customers are typically obligated to pay on a monthly basis for a specified quantity of services, whether or not those services are actually utilized. To the extent customers use more than the specified contracted minimums, the Company will charge a pre-agreed amount for the provision of such additional services.
Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate for a specified number of hours of service.
Cased-hole Wireline & Pumping Services Revenue. Through its cased-hole wireline & pumping services business, the Company provides cased-hole wireline, pumping, wireline logging, perforating, well site make-up and pressure testing and
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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
other complementary services, on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. The Company typically charges the customer for these services on a per job basis at agreed-upon spot market rates. Revenue is recognized based on a field ticket issued upon the completion of the job.
Other Completion Services Revenue. The Company generates revenue from its R&T department, which is primarily engaged in the engineering and production of certain parts and components, such as perforating guns and addressable switches, which are used in the completion process. For R&T, the performance obligation is satisfied at a point in time; revenue is recognized upon the completion, delivery and customer acceptance of each order of parts and components.
Well Construction and Intervention Services Segment
Cementing Services Revenue. The Company provides cementing services on a spot market or project basis. Jobs for these services are typically short-term in nature and are generally completed in a few hours. The Company typically charges the customer for these services on a per job basis at agreed-upon spot market rates or agreed-upon job pricing for a particular project. Revenue is recognized and customers are invoiced upon the completion of each job. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the consumables used during the course of service.
Coiled Tubing Services Revenue. The Company provides a range of coiled tubing services primarily used for fracturing plug drill-out during completion operations and for well workover and maintenance, primarily on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. Revenue is recognized upon completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the services performed and the consumables used during the course of service. The field ticket may also include charges for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables. The Company typically charges the customer for the services performed and resources provided on an hourly basis at agreed-upon spot market rates or pursuant to contractual arrangements such as term contracts and pricing agreements.
Directional Drilling Services Revenue. The Company provided directional drilling services on a spot market basis. Jobs for these services were typically short-term in nature, lasting anywhere from a few days to multiple weeks. The Company typically charged the customer for these services on a per day basis at agreed-upon spot market rates depending on the level of services required and the complexity of the job. Revenue was recognized and customers were invoiced upon the completion of each job. Once a job had been completed to the customer’s satisfaction, a field ticket was written that included charges for the service performed. During the first quarter of 2018, the Company exited their directional drilling business.
Well Support Services Segment
Rig Services Revenue. Through its rig service line, the Company provides workover and well servicing rigs that are primarily used for routine repair and maintenance of oil and gas wells, re-drilling operations and plugging and abandonment operations. These services are provided on an hourly basis at prices that approximate spot market rates. Revenue is recognized and a field ticket is generated upon the earliest of the completion of a job or at the end of each day. A rig services job can last anywhere from a few hours to multiple days depending on the type of work being performed. The field ticket includes the base hourly rate charge and, if applicable, charges for additional personnel or equipment not contemplated in the base hourly rate. The field ticket may also include charges for the mobilization and set-up of equipment.
Fluids Management Services Revenue. Through its fluids management service line, the Company primarily provides storage, transportation and disposal services for fluids used in the drilling, completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour, or per load basis, or on the basis of quantities sold or disposed. Revenue is recognized upon the completion of each job or load, or delivered product, based on a completed field ticket.
Other Special Well Site Services Revenue. Through its other special well site service line, the Company primarily provides fishing, contract labor, and tool rental services for completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour or on the basis of rental days per month. Revenue is recognized based on a field ticket issued upon the completion of each job or on a monthly billing for rental services provided.
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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
With respect to its artificial lift applications, the Company generates revenue primarily from the sale of manufactured equipment and products. Revenue is recognized upon the completion, delivery and customer acceptance of each order. During the first quarter of 2018, the Company began marketing its artificial lift business.
Remaining Performance Obligations
The Company invoices its customers for the services provided at contractual rates agreed to in pricing agreements multiplied by the applicable unit of measurement, including volume of consumables used and hours incurred. In accordance with ASC 606-10-55-18, the Company has elected the “Right to Invoice” practical expedient, which allows the Company to invoice its customers in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. Because of this election, the Company is not required to disclose information about the variable consideration related to its remaining performance obligations. Because of the short-term nature of the Company’s services, which generally last a few hours to multiple days, the Company does not have any contracts with a duration of longer than one year that require disclosure.
Contract Balances
Accounts receivable as presented on the Company’s consolidated balance sheets represent amounts due from customers for services provided as of March 31, 2018 and December 31, 2017. Bad debt expense of $1.3 million and $0.6 million was included as a component of direct costs on the consolidated statements of operations for the three months ended March 31, 2018 and 2017, respectively.
The Company does not have any contracts in which it performs services to customers but payment for those services are contingent upon a future event (e.g., satisfaction of another performance obligation). As such, there are no unbilled revenues or other contract assets recorded in the financial statements.
Significant Judgments
The majority of the Company’s performance obligations are satisfied over time. The Company has determined this best represents the transfer of control over services to the customer as performance by the Company helps to enhance a customer controlled asset (e.g., unplugging a well, enabling a well to produce oil or natural gas). Revenue is recognized over time as the Company satisfies its performance obligations. Field tickets are issued periodically throughout and upon completion of each job to evidence the services performed for each job and support the use of the output method.
Take-or-pay provisions as part of hydraulic fracturing contracts are considered stand ready performance obligations. The Company recognizes revenue for take-or-pay revenues using a time-based measure of progress, as the Company cannot reasonably estimate if and when the customer will require the use of the Company’s fleet to provide the fracturing services; likewise, the customer can benefit when a well needs fracturing services from the fleet which is standing by to provide such services.
For R&T sales, the Company recognizes revenue at the point in time the products are delivered to the customer and the customer accepts the products because the customer obtains control along with the risks and rewards of ownership of the products at such time. Once delivered, the Company has the right to invoice the customer.
The Company does not have any significant contract costs to obtain or fulfill contracts with customers; as such, no amounts are recognized on the consolidated balance sheet.
Impact of Adoption on the Financial Statements
The Company adopted ASC 606 on January 1, 2018, using the modified retrospective method for all contracts not completed as of such date. Under this method, the comparative financial statements for the periods presented prior to the adoption date are not adjusted and continue to be reported under the revenue recognition guidance of ASC 605. After reviewing the Company's contracts and the revenue recognition guidance under ASC 606 there are no material differences between revenue recognition under ASC 605 and ASC 606. As a result, there is not a cumulative effect adjustment recorded to beginning retained earnings or recognition of any contract assets or liabilities upon adoption of ASC 606.
-12-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Share-Based Compensation. The Company’s share-based compensation plan provides the ability to grant equity awards to the Company’s employees, consultants and non-employee directors. As of March 31, 2018, only nonqualified stock options, restricted shares and performance awards had been granted under such plans. The fair value of restricted stock grants is based on the closing price of C&J’s common stock on the grant date. The Company values option grants based on the grant date fair value using the Black-Scholes option-pricing model, and the Company values equity awards with market conditions based on the grant date fair value using a Monte Carlo simulation, both of which require the use of subjective assumptions. The Company recognizes share-based compensation expense on a straight-line basis over the requisite service period for the entire award. Further information regarding the Company’s share-based compensation arrangements and the related accounting treatment can be found in Note 5 - Share-Based Compensation.
Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable and accounts payable. The recorded values of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values given the short-term nature of these instruments.
Equity Method Investments. The Company has investments in joint ventures which are accounted for under the equity method of accounting as the Company has the ability to exercise significant influence over operating and financial policies of the joint venture. Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions and material intercompany transactions. Under the equity method, original investments are recorded at cost and adjusted by the Company’s share of undistributed earnings and losses of these investments. The Company eliminates all significant intercompany transactions, including the intercompany portion of transactions with equity method investees, from the consolidated financial results.
Income Taxes. The Company is subject to income and other similar taxes in all areas in which they operate. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of the Company's annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when the Company recognizes income tax expenses and benefits.
The Company accounts for income taxes utilizing the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized as income or expense in the period that includes the enactment date.
The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. In assessing the likelihood and extent that deferred tax assets will be realized, consideration is given to cumulative losses in recent years, projected future taxable income and tax planning strategies. A valuation allowance is recorded when, in the opinion of management, it is more likely than not that a portion or all of the deferred tax assets will not be realized.
The Company has federal, state and international net operating losses ("NOLs") carried forward from prior years that will expire in the years 2021 through 2037. After considering the scheduled reversal of deferred tax liabilities, projected future taxable income, the potential limitation on use of NOLs under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code") and tax planning strategies, the Company established a valuation allowance due to the uncertainty regarding the ultimate realization of the deferred tax assets associated with its NOL carryforwards.
As a result of the Chapter 11 Proceeding, on the Plan Effective Date, the Company believes it experienced an ownership change for purposes of Section 382 of the Code because of its Restructuring Plan and that consequently its pre-change NOLs are subject to an annual limitation (See Note 2 - Chapter 11 Proceeding and Emergence for additional information, including definitions of capitalized defined terms, about the Chapter 11 Proceeding and emergence from the Chapter 11 Proceeding). The ownership change and resulting annual limitation on use of NOLs are not expected to result in the expiration of the Company's NOL carryforwards if it is able to generate sufficient future taxable income within the carryforward periods. However, the limitation on the amount of NOLs available to offset taxable income in a specific year may result in the payment of income taxes before all NOLs have been utilized. Additionally, a subsequent ownership change may result in further limitation on the ability to utilize existing NOLs and other tax attributes, which could cause our pre-change
-13-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOL carryforwards to expire unused.
The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50.0% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized uncertain tax positions are reversed in the first period in which it is more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. As of March 31, 2018, the Company has no uncertain tax positions.
Earnings (Loss) Per Share. Basic earnings per share is based on the weighted average number of common shares (“common shares”) outstanding during the applicable period and excludes shares subject to outstanding stock options and shares of restricted stock. Diluted earnings per share is computed based on the weighted average number of common shares outstanding during the period plus, when their effect is dilutive, incremental shares consisting of shares subject to outstanding stock options and restricted stock.
The following is a reconciliation of the components of the basic and diluted earnings (loss) per share calculations for the applicable periods:
Successor | Predecessor | ||||||||||||
Three Months Ended March 31, 2018 | Three Months Ended March 31, 2017 | On January 1, 2017 | |||||||||||
(In thousands, except per share amounts) | (In thousands, except per share amounts) | ||||||||||||
Numerator: | |||||||||||||
Net income (loss) attributed to common stockholders | $ | 20,594 | $ | (32,301 | ) | $ | 298,582 | ||||||
Denominator: | |||||||||||||
Weighted average common shares outstanding | 67,186 | 55,557 | 118,633 | ||||||||||
Effect of potentially dilutive common shares: | |||||||||||||
Stock options | — | — | — | ||||||||||
Warrants | 76 | — | — | ||||||||||
Restricted shares | 4 | — | — | ||||||||||
Weighted average common shares outstanding and assumed conversions | 67,266 | 55,557 | 118,633 | ||||||||||
Income (loss) per common share: | |||||||||||||
Basic | $ | 0.31 | $ | (0.58 | ) | $ | 2.52 | ||||||
Diluted | $ | 0.31 | $ | (0.58 | ) | $ | 2.52 | ||||||
A summary of securities excluded from the computation of basic and diluted earnings (loss) per share is presented below for the applicable periods:
Successor | Predecessor | ||||||||
Three Months Ended March 31, 2018 | Three Months Ended March 31, 2017 | On January 1, 2017 | |||||||
(In thousands) | (In thousands) | ||||||||
Basic earnings (loss) per share: | |||||||||
Restricted shares | 1,281 | 299 | 898 | ||||||
Diluted earnings (loss) per share: | |||||||||
Anti-dilutive stock options | 351 | 155 | 4,416 | ||||||
Anti-dilutive restricted shares | 1,272 | 299 | 898 | ||||||
Potentially dilutive securities excluded as anti-dilutive | 1,623 | 454 | 5,314 | ||||||
-14-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Recent Accounting Pronouncements. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). ASU No. 2016-02 seeks to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and by disclosing key information about leasing arrangements. Unlike current U.S. GAAP, which requires only capital leases to be recognized on the balance sheet, ASU No. 2016-02 will require both operating and finance leases to be recognized on the balance sheet. Additionally, the new guidance will require disclosures to help investors and other financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements. The amendments in ASU No. 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. The Company will adopt this new accounting standard on January 1, 2019. The Company is currently determining the impacts of the new standard on its consolidated financial statements. The approach includes performing a detailed review of its lease portfolio by evaluating its population of leased assets and designing and implementing new processes and controls.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which amends U.S. GAAP by introducing a new impairment model for financial instruments that is based on expected credit losses rather than incurred credit losses. The new impairment model applies to most financial assets, including trade accounts receivable. The amendments in ASU 2016-13 are effective for interim and annual reporting periods beginning after December 15, 2019, although it may be adopted one year earlier, and requires a modified retrospective transition approach. The Company is currently evaluating the impact this standard will have on its consolidated financial statements.
In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory ("ASU 2016-16"), which requires an entity to recognize the income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory, when the transfer occurs. The ASU is effective for the interim and annual reporting periods beginning after December 15, 2017, including interim periods within those fiscal years, and early application is permitted. The Company adopted this new accounting standard on January 1, 2018. The Company recognized a cumulative effect adjustment as a reduction to retained earnings of $13.2 million which occurred as a result of the Company's adoption of ASU 2016-16.
In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"), which establishes a one-step process for testing goodwill for a drop in value. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019 and early adoption is permitted. The Company adopted this new accounting standard on January 1, 2018, and there was no impact on its consolidated financial statements.
In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ("ASU 2018-02"), which allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act and requires certain disclosures about stranded tax effects. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently evaluating the impact of this standard on its consolidated financial statements.
In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118, ("ASU 2018-05"), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (the Tax Act) pursuant to Staff Accounting Bulletin No. 18, which allows companies to complete the accounting under ASC 740 within a one-year measurement period from the Tax Act enactment date. This standard is effective upon issuance. The Company is currently evaluating the impact of this standard on its consolidated financial statements.
Note 2 - Chapter 11 Proceeding and Emergence
On July 8, 2016, C&J Energy Services Ltd., a Bermuda corporation (the “Predecessor”) and certain of its direct and indirect subsidiaries (collectively, the “Debtors”), including C&J Corporate Services (Bermuda) Ltd. (together with the Predecessor, the “Bermudian Entities”), C&J Energy Production Services-Canada Ltd. and Mobile Data Technologies Ltd. (together, the “Canadian Entities”), entered into a Restructuring Support and Lock-Up Agreement (the “Restructuring Support Agreement”), with certain lenders (the “Supporting Lenders”) holding approximately 90.0% of the secured claims and interests arising under the Credit Agreement, dated as of March 24, 2015 (as amended and otherwise modified, the “Original Credit Agreement”). The Restructuring Support Agreement contemplated the implementation of a financial restructuring of the
-15-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Company, including the elimination of all amounts owed under the Original Credit Agreement through a complete debt-to-equity conversion and a re-investment in the Company through an equity rights offering. This financial restructuring was effectuated through the Restructuring Plan under Chapter 11 of the Bankruptcy Code.
To implement the Restructuring Support Agreement, on July 20, 2016 (the “Petition Date”), the Debtors filed voluntary petitions for reorganization (the “Bankruptcy Petitions”) seeking relief under the provisions of Chapter 11 of the Bankruptcy Code with the United States Bankruptcy Court in the Southern District of Texas, Houston Division (the “Bankruptcy Court”), and also commenced ancillary proceedings in Canada on behalf of the Canadian Entities and a provisional liquidation proceeding in Bermuda on behalf of the Bermudian Entities (collectively, the “Chapter 11 Proceeding”). The Chapter 11 Proceeding was being administered under the caption “In re: CJ Holding Co., et al., Case No. 16-33590”. Throughout the Chapter 11 Proceeding, the Debtors continued operations and management of their assets in the ordinary course as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
In accordance with the Restructuring Support Agreement, the Debtors filed the plan of reorganization (the " Restructuring Plan") and related disclosure statement (the “Disclosure Statement”) with the Bankruptcy Court on August 19, 2016, with a first amendment to the Restructuring Plan filed on September 28, 2016 and a second amendment filed on November 3, 2016. On November 4, 2016, the Bankruptcy Court approved the Disclosure Statement, finding that the Disclosure Statement contained adequate information as required by the Bankruptcy Code. The Debtors then launched a solicitation of acceptances of the Restructuring Plan, as required by the Bankruptcy Code. On December 16, 2016, an order confirming the Restructuring Plan was entered by the Bankruptcy Court. On January 6, 2017 (the "Plan Effective Date"), the Debtors substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. As part of the transactions undertaken pursuant to the Restructuring Plan, as of the Plan Effective Date, the Successor was formed, the Predecessor's equity was canceled, the Predecessor transferred all of its assets and operations to the Successor and the Predecessor was subsequently dissolved. As a result, the Successor became the successor issuer to the Predecessor. For additional information regarding the Chapter 11 Proceeding and Emergence, please read the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.
Reorganization Items
The Company classifies all income, expenses, gains or losses that were incurred or realized as a result of the Chapter 11 Proceeding as reorganization items in its consolidated statements of operations. In addition, the Company reports professional fees and related costs associated with and incurred during the Chapter 11 Proceeding as reorganization items. The components of reorganization items are as follows (in thousands):
On January 1, 2017 | |||
Gain on settlement of liabilities subject to compromise | $ | 666,399 | |
Net loss on fresh start fair value adjustments | (358,557 | ) | |
Professional fees | (13,435 | ) | |
Vendor claims adjustment | (438 | ) | |
Total reorganization items | $ | 293,969 | |
While the Company’s emergence from bankruptcy is complete, certain administrative activities will continue under the authority of the Bankruptcy Court for at least the next several months.
Note 3 - Debt
New Credit Facility
The Company and certain of its subsidiaries (the “Borrowers”) entered into an asset-based revolving credit agreement with, among others, JPMorgan Chase Bank, N.A., as administrative agent (the “Agent”), on May 1, 2018 (the “New Credit Facility”).
The New Credit Facility allows the Borrowers to incur revolving loans in an aggregate amount up to the lesser of (a) $400.0 million or (b) a borrowing base (the “Loan Cap”), which borrowing base is based upon the value of the Borrowers’
-16-
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
accounts receivable, inventory and restricted cash, subject to eligibility criteria and customary reserves which may be modified in the Agent’s permitted discretion.
The New Credit Facility also provides for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the New Credit Facility is May 1, 2023.
If at any time the amount of loans and other extensions of credit outstanding under the New Credit Facility exceed the borrowing base, the Borrowers may be required, among other things, to prepay outstanding loans immediately.
The Borrowers’ obligations under the New Credit Facility are secured by liens on a substantial portion of the Borrowers’ personal property, subject to certain exclusions and limitations. Upon the occurrence of certain events, additional collateral, including a portion of the Borrowers’ real properties, may also be required to be pledged. Each of the Borrowers is jointly and severally liable for the obligations of the other Borrowers under the New Credit Facility.
At the Borrowers’ election, interest on borrowings under the New Credit Facility will be determined by reference to either LIBOR plus an applicable margin of between 1.5% and 2.0% or an “alternate base rate” plus an applicable margin of between 0.5% and 1.0%, in each case based on the Company’s total leverage ratio. Interest will be payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans and, in the case of an interest period longer than three months, quarterly, upon any prepayment and at final maturity. The Borrowers will also be required to pay a fee on the unused portion of the New Credit Facility equal to (i) 0.5% per annum if average utilization is less than or equal to 25% or (ii) 0.375% per annum if average utilization is greater than 25%, in each case payable quarterly in arrears to the Agent.
The New Credit Facility contains covenants that limit the Borrowers’ ability to incur additional indebtedness, grant liens, make loans, make acquisitions or investments, make distributions, merge into or consolidate with other persons, or engage in certain asset dispositions.
The New Credit Facility also contains a financial covenant which requires the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 upon the occurrence of an event of default or on any date upon which the excess availability is less than the greater of (x) 12.5% of the lesser of the Loan Cap and (y) $30.0 million.
The fixed charge coverage ratio is generally defined in the New Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.
Prior Credit Facility
On January 6, 2017, in connection with the emergence from bankruptcy, the Company entered into a revolving credit and security agreement with PNC Bank, National Association, as administrative agent (the “Prior Agent”), which was subsequently amended and restated on May 4, 2017 (the “Prior Credit Facility”). The Prior Credit Facility was canceled and discharged on May 1, 2018.
The Prior Credit Facility allowed the Company and certain of its subsidiaries (the “Prior Borrowers”), to incur revolving loans in an aggregate amount up to the lesser of $200.0 million and a borrowing base, which borrowing base was based upon the value of the Prior Borrowers’ accounts receivable and inventory, subject to eligibility criteria and customary reserves which may have been modified in the Agent’s permitted discretion. The Prior Credit Facility also provided for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the Prior Credit Facility was May 4, 2022.
If at any time the amount of loans and other extensions of credit outstanding under the Prior Credit Facility exceeded the borrowing base, the Prior Borrowers may have been required, among other things, to prepay outstanding loans immediately.
The Prior Borrowers’ obligations under the Prior Credit Facility were secured by liens on a substantial portion of the Prior Borrowers’ personal property, subject to certain exclusions and limitations. Upon the occurrence of certain events, additional collateral, including a portion of the Prior Borrowers’ real properties, may also have been required to be pledged.
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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Each of the Prior Borrowers was jointly and severally liable for the obligations of the other Prior Borrowers under the Prior Credit Facility.
At the Prior Borrowers’ election, interest on borrowings under the Prior Credit Facility would have been determined by reference to either LIBOR plus an applicable margin of 2.0% or an “alternate base rate” plus an applicable margin of 1.0%. Beginning after the fiscal month ending on or about September 30, 2017, these margins were subject to a monthly step-up of 0.25% in the event that average excess availability under the Prior Credit Facility was less than 37.5% of the total commitment, and a monthly step-down of 0.25% in the event that average excess availability under the Prior Credit Facility was equal to or greater than 62.5% of the total commitment. Interest was payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans. The Prior Borrowers were also required to pay a fee on the unused portion of the Prior Credit Facility equal to (i) 0.75% in the event that utilization was less than 25% of the total commitment, (ii) 0.50% in the event utilization was equal to or greater than 25% of the total commitment but less than 50% of the total commitment and (iii) 0.375% in the event that utilization was equal to or greater than 50% of the total commitment.
The Prior Credit Facility contained covenants that limited the Prior Borrowers’ ability to incur additional indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, make capital expenditures or engage in certain asset dispositions including a sale of all or substantially all of the Company’s assets.
The Prior Credit Facility also contained a financial covenant that required the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 if, as of any month-end, liquidity was less than $40.0 million.
The fixed charge coverage ratio was generally defined in the Prior Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.
As of March 31, 2018, the Company was in compliance with all financial covenants of the Prior Credit Facility.
Note 4 - Goodwill and Other Intangible Assets
On November 30, 2017, the Company acquired all of the outstanding equity interests of O-Tex Holdings, Inc., and its operating subsidiaries (“O-Tex”). See Note 8 - Mergers and Acquisitions for further discussion on the O-Tex acquisition. As of March 31, 2018, all of the goodwill reported on the Company's consolidated balance sheet is related to the O-Tex acquisition, which was allocated to the Company's Well Construction and Intervention Services reporting unit.
There were no changes in the carrying amount of goodwill for the three months ended March 31, 2018.
Definite-Lived Intangible Assets
The Company reviews definite-lived intangible assets, along with PP&E, for impairment when a triggering event indicates that the asset may have a net book value in excess of recoverable value.
The changes in the carrying amounts of other intangible assets for the three months ended March 31, 2018 are as follows (in thousands):
Amortization Period | December 31, 2017 | Amortization Expense | March 31, 2018 | |||||||||||
Customer relationships | 8-15 years | $ | 58,100 | $ | — | $ | 58,100 | |||||||
Trade name | 10-15 years | 68,300 | — | 68,300 | ||||||||||
Non-compete | 4-5 years | 1,600 | — | 1,600 | ||||||||||
128,000 | — | 128,000 | ||||||||||||
Less: accumulated amortization | (4,163 | ) | (2,205 | ) | (6,368 | ) | ||||||||
Intangible assets, net | $ | 123,837 | $ | (2,205 | ) | $ | 121,632 | |||||||
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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 5 - Share-Based Compensation
Pursuant to the Restructuring Plan, the Company adopted the C&J Energy Services, Inc. 2017 Management Incentive Plan (as amended from time to time, the “MIP”) as of the Plan Effective Date.
The MIP provides for the grant of share-based awards to the Company’s employees, consultants and non-employee directors. The following types of awards are available for issuance under the MIP: incentive stock options and nonqualified stock options, share appreciation rights, restricted shares, restricted share units, dividend equivalent rights, performance awards, share awards, other share-based awards and substitute awards. As of March 31, 2018, only nonqualified stock options, restricted shares and performance awards have been awarded under the MIP.
A total of approximately 8.0 million shares of common stock were originally authorized and approved for issuance under the MIP. The number of shares of common stock available for issuance under the MIP is subject to adjustment in the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, issuance of warrants, rights or debentures, share dividend, share split or reverse share split, cash dividend, property dividend, combination or exchange of shares, repurchase of shares, change in corporate structure or any similar corporate event or transaction. The number of shares of common stock available for issuance may also increase due to the termination of an award granted under the MIP or by expiration, forfeiture, cancellation or otherwise without the issuance of the common stock.
Stock Options
The fair value of each option award granted under the MIP is estimated on the date of grant using the Black-Scholes option-pricing model. Determination of the fair value was a matter of judgment and often involved the use of significant estimates and assumptions. Additionally, due to the Company’s lack of historical volume of option activity, the expected term of options granted was derived using the “plain vanilla” method. Expected volatilities were based on comparable public company data, with consideration given to the Company’s limited historical data. The Company makes estimates with respect to employee termination and forfeiture rates of the options within the valuation model. The risk-free rate is based on the approximate U.S. Treasury yield rate in effect at the time of grant. During the first quarter of 2017, approximately 0.3 million nonqualified stock options were granted under the MIP to certain of the Company's executive officers at a fair market value of $22.19 per nonqualified stock option. These option awards will expire on the tenth anniversary of the grant date and will vest over three years of continuous service from the grant date, with 34% vesting immediately upon the grant date, and 22% on each of the first, second and third anniversaries of the grant date. During the three months ended March 31, 2018, no stock options were granted by the Company.
As of March 31, 2018, the Company had approximately 0.3 million options outstanding to employees, including 0.2 million unvested options. The Company had approximately $3.4 million of share-based compensation remaining to be expensed over a weighted average remaining service period of 2.2 years.
The following table includes the assumptions used in determining the fair value of option awards granted during the first three months of 2017.
Expected volatility | 50.1% | |
Expected dividends | None | |
Exercise price | $42.65 | |
Expected term (in years) | 5.7 | |
Risk-free rate | 2.03% | |
Restricted Stock
The value of the Company’s outstanding restricted stock is based on the closing price of the Company’s common stock on the NYSE on the date of grant. During the first quarter of 2017, approximately 0.9 million shares of restricted stock were granted to employees and non-employee directors under the MIP, at fair market values ranging from $43.00 to $44.90 per share of restricted stock. Restricted stock awards granted to employees during the first quarter of 2017 will vest over three years of continuous service from the grant date, with 34% having vested immediately upon the grant date, and 22% on each of the first, second and third anniversaries of the grant date. Restricted stock awards granted to non-employee directors will vest in full on the first anniversary of the date of grant, subject to each director's continued service. During the three months ended March 31, 2018, no restricted shares were granted by the Company.
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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
To the extent permitted by law, the recipient of an award of restricted stock will generally have all of the rights of a stockholder with respect to the underlying common stock, including the right to vote the common stock and to receive all dividends or other distributions made with respect to the common stock. Dividends on restricted stock will be deferred until the lapsing of the restrictions imposed on the stock and will be held by the Company for the account of the recipient (either in cash or to be reinvested in restricted stock) until such time. Payment of the deferred dividends and accrued interest, if any, shall be made upon the lapsing of restrictions on the restricted stock, and any dividends deferred in respect of any restricted stock shall be forfeited upon the forfeiture of such restricted stock. As of March 31, 2018, the Company had not issued any dividends.
As of March 31, 2018, the Company had approximately 1.2 million shares of restricted stock outstanding to employees and non-employee directors. The Company had $36.3 million of share-based compensation remaining to be expensed over a weighted average remaining service period of 2.4 years.
Note 6 - Commitments and Contingencies
Environmental Regulations & Liabilities
The Company is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for the protection of the environment. The Company continues to monitor the status of these laws and regulations. However, the Company cannot predict the future impact of such standards and requirements on its business, which are subject to change and can have retroactive effectiveness.
Currently, the Company has not been fined, cited or notified of any environmental violations or liabilities that would have a material adverse effect upon its consolidated financial position, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could be incurred in the near term to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the corrective actions which may be required, the determination of the Company’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.
Litigation
The Company is, and from time to time may be, involved in claims and litigation arising in the ordinary course of business. Because there are inherent uncertainties in the ultimate outcome of such matters, it is presently not possible to determine the ultimate outcome of any pending or potential claims or litigation against the Company; however, management believes that the outcome of those matters that are presently known to the Company will not have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.
Contingent Consideration Liability
On May 18, 2015, the Company acquired all of the outstanding equity interests of ESP Completion Technologies LLC, a manufacturer of wellheads, artificial lift completion tools and electric submersible pumps for approximately $34.0 million and including a contingent consideration liability valued at approximately $14.4 million at the date of the acquisition. If the acquiree is able to achieve certain levels of EBITDA over a three-year period, the Company would be obligated to make future tiered payments of up to $29.5 million. The contingent consideration liability is remeasured on a fair value basis each quarter until it is paid or expires. As of March 31, 2018, the earn-out was estimated to have zero value.
Self-Insured Risk Accruals
The Company maintains insurance policies for workers’ compensation, automobile liability, general liability, which also includes sudden and accidental pollution insurance, environmental liability, and property damage relating to catastrophic events, together with excess loss liability coverage. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The Company has deductibles per occurrence for: (i) workers’ compensation of $1,000,000; (ii) automobile liability claims of $1,000,000; (iii) general liability claims, including sudden and accidental pollution claims, of $250,000, plus an additional annual aggregate deductible of $250,000; (iv) environmental liability claims of $500,000; and (v) property damage for catastrophic events of $50,000. The excess loss liability coverage is subject to an annual aggregate self-insured retention of $5,000,000.
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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Additionally, under the terms of the Separation Agreement, dated as of February 12, 2015, by and between the Predecessor and Nabors Industries, Ltd. (“Nabors”), relating to a transformative transaction between the Predecessor and Nabors (the “Nabors Merger”), with the exception of certain liabilities for which Nabors has agreed to indemnify the Predecessor, the Predecessor assumed, among other liabilities, all liabilities of the completion and production services business (the “C&P Business”) to the extent arising out of or resulting from the operation of the C&P Business at any time before, at or after the closing of the Nabors Merger, including liability for death, personal injury and property damage resulting from or caused by the assets, products and services of the C&P Business. Any liability relating to or resulting from any claim or litigation asserted after the closing of the Nabors Merger, but where the underlying cause of action arose prior to that time, would not be covered by the Company’s insurance policies.
Note 7 - Segment Information
In accordance with ASC No. 280 - Segment Reporting, the Company routinely evaluates whether its separate operating and reportable segments have changed. This determination is made based on the following factors: (1) the Company’s chief operating decision maker (“CODM”) is currently managing each operating segment as a separate business and evaluating the performance of each segment and making resource allocation decisions distinctly and expects to do so for the foreseeable future, and (2) discrete financial information for each operating segment is available.
Prior to and as of the year ended December 31, 2017, the Company’s reportable segments were: (i) Completion Services and (ii) Well Support Services. Due to the significant expansion of C&J's cementing business, during the first quarter of 2018 the CODM revised the approach in which performance evaluation and resource allocation decisions are made. Discrete financial information was created to provide the segment information necessary for the CODM to manage the Company under the revised operating segment structure. As a result of this change in operating segments, the Company revised its reportable segments in the first quarter of 2018. The Company's operating and reportable segments are now: (i) Completion Services, (ii) Well Construction and Intervention Services and (iii) Well Support Services. This segment structure reflects the financial information and reports used by the Company’s management, including its CODM, to make decisions regarding the Company’s business, including performance evaluation and resource allocation decisions. As a result of the revised reportable segment structure, the Company has restated the corresponding segment information for all periods presented.
The following is a brief description of the Company's reportable segments:
Completion Services
The Company’s Completion Services segment consists of the following businesses and service lines: (1) fracturing services; (2) cased-hole wireline and pumping services; and (3) completion support services, which includes the Company's R&T department.
Well Construction and Intervention Services
The Company’s Well Construction and Intervention Services segment consists of the following businesses and service lines: (1) cementing services; (2) coiled tubing services and (3) directional drilling services. During the first quarter of 2018, the Company exited its directional drilling business.
Well Support Services
The Company’s Well Support Services segment consists of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) special services, which includes plug and abandonment, artificial lift applications and other specialty well site services. During the first quarter of 2018, the Company began marketing its artificial lift business.
The following table sets forth certain financial information with respect to the Company’s reportable segments.
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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Completion Services | Well Construction and Intervention Services | Well Support Services | Corporate / Elimination | Total | ||||||||||||||||
Three months ended March 31, 2018 | ||||||||||||||||||||
Revenue from external customers | $ | 374,145 | $ | 87,417 | $ | 91,438 | $ | — | $ | 553,000 | ||||||||||
Inter-segment revenues | 319 | — | 105 | (424 | ) | — | ||||||||||||||
Depreciation and amortization | 23,137 | 9,932 | 12,342 | 932 | 46,343 | |||||||||||||||
Operating income (loss) | 57,806 | 5,460 | (8,834 | ) | (34,090 | ) | 20,342 | |||||||||||||
Net income (loss) | 57,874 | 5,456 | (8,650 | ) | (34,086 | ) | 20,594 | |||||||||||||
Adjusted EBITDA | 80,894 | 16,001 | 5,107 | (28,316 | ) | 73,686 | ||||||||||||||
Capital expenditures | 57,125 | 3,642 | 2,206 | 55 | 63,028 | |||||||||||||||
As of March 31, 2018 | ||||||||||||||||||||
Total assets | $ | 769,928 | $ | 417,582 | $ | 277,383 | $ | 141,444 | $ | 1,606,337 | ||||||||||
Goodwill | — | 147,515 | — | — | 147,515 | |||||||||||||||
Three months ended March 31, 2017 | ||||||||||||||||||||
Revenue from external customers | $ | 191,809 | $ | 26,119 | $ | 96,266 | $ | — | $ | 314,194 | ||||||||||
Inter-segment revenues | 279 | — | 40 | (319 | ) | — | ||||||||||||||
Depreciation and amortization | 15,922 | 2,689 | 12,007 | 988 | 31,606 | |||||||||||||||
Operating income (loss) | 10,845 | (535 | ) | (8,233 | ) | (38,485 | ) | (36,408 | ) | |||||||||||
Net income (loss) | 10,321 | (535 | ) | (6,488 | ) | (35,599 | ) | (32,301 | ) | |||||||||||
Adjusted EBITDA | 21,705 | 1,037 | 3,824 | (21,982 | ) | 4,584 | ||||||||||||||
Capital expenditures | 7,088 | 388 | 3,981 | 128 | 11,585 | |||||||||||||||
As of March 31, 2017 | ||||||||||||||||||||
Total assets | $ | 467,578 | $ | 77,166 | $ | 341,251 | $ | 213,007 | $ | 1,099,002 | ||||||||||
Management evaluates reportable segment performance and allocates resources based on total earnings (loss) before net interest expense, income taxes, depreciation and amortization, other income (expense), net gain or (loss) on disposal of assets, acquisition-related costs, and non-routine items (“Adjusted EBITDA”), because Adjusted EBITDA is considered an important measure of each reportable segment’s performance. In addition, management believes that the disclosure of Adjusted EBITDA as a measure of each reportable segment’s operating performance allows investors to make a direct comparison to competitors, without regard to differences in capital and financing structure. Investors should be aware, however, that there are limitations inherent in using Adjusted EBITDA as a measure of overall profitability because it excludes significant expense items. An improving trend in Adjusted EBITDA may not be indicative of an improvement in the Company’s profitability. To compensate for the limitations in utilizing Adjusted EBITDA as an operating measure, management also uses U.S. GAAP measures of performance, including operating income (loss) and net income (loss), to evaluate performance, but only with respect to the Company as a whole and not on a reportable segment basis.
As required under Item 10(e) of Regulation S-K of the Exchange Act, included below is a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure (in thousands) on a consolidated basis for the three months ended March 31, 2018 and 2017.
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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Three Months Ended March 31, 2018 | Three Months Ended March 31, 2017 | |||||||
Net income (loss) | $ | 20,594 | $ | (32,301 | ) | |||
Interest expense, net | 428 | 691 | ||||||
Income tax benefit | (60 | ) | (3,236 | ) | ||||
Depreciation and amortization | 46,343 | 31,606 | ||||||
Other (income) expense, net | (620 | ) | (1,562 | ) | ||||
Gain on disposal of assets | (489 | ) | (6,056 | ) | ||||
Acquisition-related and other transaction costs | 727 | — | ||||||
Severance, facility closures and other | 4,238 | — | ||||||
Restructuring costs | 623 | (216 | ) | |||||
Share-based compensation expense acceleration | 1,902 | 15,658 | ||||||
Adjusted EBITDA | $ | 73,686 | $ | 4,584 | ||||
Note 8 - Mergers and Acquisitions
Acquisition of O-Tex
On November 30, 2017, the Company acquired all of the outstanding equity interest of O-Tex for approximately $271.9 million, consisting of cash of approximately $132.5 million and 4.42 million shares of the Company's common stock with a fair value of $138.2 million. The Company also acquired the remaining 49.0% non-controlling interest in an O-Tex subsidiary for $1.25 million.
The O-Tex transaction was accounted for using the acquisition method of accounting for business combinations. The preliminary purchase price was allocated to the net assets acquired based upon their estimated fair values. The estimated fair values of certain assets and liabilities, including property plant and equipment, other intangible assets, and contingencies required significant judgments and estimates. As a result, the provisional measurements are preliminary and subject to change during the measurement period and such changes could be material. As of March 31, 2018, there were no changes to the acquisition date fair value of assets acquired and liabilities assumed.
The following unaudited pro forma results of operations have been prepared as though the O-Tex transaction was completed on January 1, 2016. Pro forma amounts are based on the purchase price allocation of the acquisition and are not necessarily indicative of results that may be reported in the future (in thousands):
Three Months Ended March 31, 2017 | ||||
Revenues | $ | 350,782 | ||
Net loss | $ | (36,027 | ) | |
Note 9 - Supplemental Cash Flow Disclosures
Listed below are supplemental cash flow disclosures for the three months ended March 31, 2018 and 2017 and the Fresh Start Reporting Date:
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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Successor | Predecessor | ||||||||||||
Three Months Ended March 31, 2018 | Three Months Ended March 31, 2017 | On January 1, 2017 | |||||||||||
Cash paid for interest | $ | (305 | ) | $ | (664 | ) | $ | — | |||||
Income taxes refunded | $ | 3,718 | $ | 542 | $ | — | |||||||
Reorganization items, cash | $ | — | $ | — | $ | (21,657 | ) | ||||||
Non-cash investing and financing activity: | |||||||||||||
Change in accrued capital expenditures | $ | 771 | $ | (5,869 | ) | $ | — | ||||||
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes certain statements and information that may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “plan,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “will,” “could,” “should,” “potential,” “would,” “may,” “probable,” “likely,” and similar expressions that convey the uncertainty of future events or outcomes, and the negative thereof, are intended to identify forward-looking statements. Forward-looking statements, which are not generally historical in nature, include those that express a belief, expectation or intention regarding our future activities, plans and goals and our current expectations with respect to, among other things, our business strategy and our financial strategy.
Forward-looking statements are not assurances of future performance and actual results could differ materially from our historical experience and our present expectations or projections. These forward-looking statements are based on management’s current expectations and beliefs, forecasts for our existing operations, experience, expectations and perception of historical trends, current conditions, anticipated future developments and their effect on us, and other factors believed to be appropriate. Although management believes the expectations and assumptions reflected in these forward-looking statements are reasonable as and when made, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all). Our forward-looking statements involve significant risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Known material factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, risks associated with the following:
• | a decline in demand for our services, including due to declining commodity prices, overcapacity and other competitive factors affecting our industry; |
• | the cyclical nature and volatility of the oil and gas industry, which impacts the level of drilling, completion and production activity and spending patterns by our customers; |
• | a decline in, or substantial volatility of, crude oil and gas commodity prices, which generally leads to decreased spending by our customers and negatively impacts drilling, completion and production activity; |
• | pressure on pricing for our core services, including due to competition and industry and/or economic conditions, which may impact, among other things, our ability to implement price increases or maintain pricing on our core services; |
• | the loss of, or interruption or delay in operations by, one or more significant customers; |
• | the failure by one or more of our significant customers to pay amounts when due, or at all; |
• | changes in customer requirements in the markets we serve; |
• | costs, delays, compliance requirements and other difficulties in executing our short-and long-term business plans and growth strategies; |
• | the effects of recent or future acquisitions on our business, including our ability to successfully integrate our operations and the costs incurred in doing so; |
• | business growth outpacing the capabilities of our infrastructure; |
• | operating hazards inherent in our industry, including the possibility of accidents resulting in personal injury or death, property damage or environmental damage; |
• | adverse weather conditions in oil or gas producing regions; |
• | the loss of, or interruption or delay in operations by, one or more of our key suppliers; |
• | the effect of environmental and other governmental regulations on our operations, including the risk that future changes in the regulation of hydraulic fracturing could reduce or eliminate demand for our hydraulic fracturing services; |
• | the incurrence of significant costs and liabilities resulting from litigation; |
• | the incurrence of significant costs and liabilities or severe restrictions on our operations or the inability to perform certain operations resulting from a failure to comply, or our compliance with, new or existing regulations; |
• | the effect of new or existing regulations, industry and/or commercial conditions on the availability of and costs for raw materials, consumables and equipment; |
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• | the loss of, or inability to attract, key management and other competent personnel; |
• | a shortage of qualified workers; |
• | damage to or malfunction of equipment; |
• | our ability to maintain sufficient liquidity and/or obtain adequate financing to allow us to execute our business plan; and |
• | our ability to comply with covenants under our New Credit Facility. |
For additional information regarding known material factors that could affect our operating results and performance, please read (1) “Risk Factors” in Part II, Item 1A of this Quarterly Report, as well as “Risk Factors” in Part I, Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 (our “2017 Annual Report”); and (2) “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I, Item 2 of this Quarterly Report, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our 2017 Annual Report. Should one or more of these known material risks occur, or should the underlying assumptions prove incorrect, our actual results, performance, achievements or plans could differ materially from those expressed or implied in any forward-looking statement.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise, except as required by law.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report, together with the audited consolidated financial statements and notes thereto and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2017 Annual Report.
This section contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in any forward-looking statement because of various factors, including those described in the section titled “Cautionary Note Regarding Forward-Looking Statements” in Part I, Financial Statements of this Quarterly Report and “Risk Factors” in Part II, Item 1A of this Quarterly Report.
Introductory Note and Overview
C&J Energy Services, Inc., a Delaware corporation (“C&J,” the “Company,” “we,” “us” or “our”), is a leading provider of well construction and intervention, well completion, well support and other complementary oilfield services and technologies to oil and gas exploration and production (“E&P”) companies throughout the continental United States. We are a completions-focused service provider offering a diverse, integrated suite of services across the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, rig services, fluids management and other completion and specialty well site support services. We are headquartered in Houston, Texas and operate in all active onshore basins in the continental United States.
We were founded in Texas in 1997. On April 12, 2017, following the successful completion of a financial restructuring (see Note 2 - Chapter 11 Proceeding and Emergence in Part I, Item 1 “Financial Statements” of this Quarterly Report), we completed an underwritten public offering of common stock and began trading on the New York Stock Exchange (“NYSE”) under the symbol “CJ.”
We file annual, quarterly and current reports and other documents with the U.S. Securities and Exchange Commission (“SEC”) under the Exchange Act. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operations of the Public Reference Room by calling the SEC at (800) SEC-0330. In addition, the SEC maintains a website at www.sec.gov that contains reports and other information regarding issuers that file electronically with the SEC.
Our principal executive offices are located at 3990 Rogerdale Road, Houston, Texas 77042 and our main telephone number at that address is (713) 325-6000. Our website is available at www.cjenergy.com. We make available free of charge through our website all reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act, including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statement on Schedule 14A and all amendments to those reports, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Information contained on or available through our website is not a part of or incorporated into this Quarterly Report or any other report that we may file with or furnish to the SEC.
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Reportable Segments
During the first quarter of 2018, we revised our reportable segments. As a result of the revised reportable segment structure, we have restated the corresponding items of the segment information for all periods presented. As of March 31, 2018, our reportable business segments were:
• | Completion Services, which consists of the following businesses and service lines: (1) fracturing services; (2) cased-hole wireline and pumping services; and (3) completion support services, which includes our research and technology (“R&T”) department. |
• | Well Construction and Intervention Services, which consists of the following businesses and service lines: (1) cementing services; (2) coiled tubing services; and (3) directional drilling services. |
• | Well Support Services, which consists of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) special services, which includes plug and abandonment, artificial lift applications and other specialty well site services. |
During the first quarter of 2018, we decided to exit our directional drilling business and artificial lift business, and we are in the process of divesting the assets and inventory.
Our reportable business segments are described in more detail below; for financial information about our reportable business segments, including revenue from external customers and total assets by reportable business segment, please see Note 7 - Segment Information in Part I, Item 1 “Financial Statements” of this Quarterly Report.
Completion Services
The core services provided through our Completion Services segment are fracturing and cased-hole wireline and pumping services. Our completion support services are focused on supporting the efficiency and effectiveness of our operations, including a newly established logistics services department, the primary purpose of which is to satisfy a portion of our internal sand hauling needs. Our R&T department provides in-house manufacturing capabilities that generates cost savings to our operations and enables us to offer technologically advanced and efficiency focused completion services. Through our R&T department we manufacture the data control instruments used in our fracturing operations and the perforating guns and addressable switches used in our wireline operations; these products are also sold to third-parties. The majority of revenue for this segment is generated by our fracturing business.
During the first quarter of 2018, our fracturing business deployed, on average, approximately 630,000 hydraulic horsepower (“HHP”) out of our current fleet of approximately 900,000 HHP as of March 31, 2018. We exited the first quarter of 2018 with approximately 655,000 HHP deployed consisting of fifteen horizontal and two vertical frac fleets. Our typical horizontal fleet size consists of 20 pumps, or approximately 40,000 HHP, and our typical vertical fleet size consists of 10 pumps, or approximately 20,000 HHP. In our cased-hole wireline and pumping business , we deployed, on average, approximately 67 wireline trucks and 72 pumpdown units out of our current fleet of 124 trucks and 74 pumpdown units, respectively, during the first quarter of 2018. We experienced a sequential decline in our average wireline truck count in the first quarter of 2018 due to customer job mix and labor shortages. Not all of our deployed assets are utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.
Management evaluates the operational performance of our Completion Services segment and allocates resources primarily based on Adjusted EBITDA because management believes that Adjusted EBITDA provides important information about the activity and profitability of our lines of business within this segment. Adjusted EBITDA is computed as total earnings (loss) before net interest expense, income taxes, depreciation and amortization, other income (expense), net, gain or loss on disposal of assets, acquisition-related costs, and non-routine items.
For the quarter ended March 31, 2018, revenue from our Completion Services segment was $374.1 million, representing approximately 67.7% of our total revenue, compared with revenue of $343.2 million for the quarter ended December 31, 2017, which represented a 9.0% quarter-over-quarter increase. Adjusted EBITDA from this segment for the quarter ended March 31, 2018, was $80.9 million, compared with $72.6 million of Adjusted EBITDA for the quarter ended December 31, 2017. The following table presents revenue and other operational data for our Completion Services segment for the three months ended March 31, 2018 and 2017 (dollars in thousands). Please also read Note 7 - Segment Information in Part I, Item 1 “Financial Statements” of this Quarterly Report, for a reconciliation of Adjusted EBITDA, a non-GAAP financial
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measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure (in thousands) for the three months ended March 31, 2018 and 2017.
Three Months Ended | |||||||
March 31, 2018 | March 31, 2017 | ||||||
Revenue | |||||||
Fracturing | $ | 269,491 | $ | 130,663 | |||
Cased-hole Wireline & Pumping | 99,754 | 56,265 | |||||
Other | 4,900 | 4,881 | |||||
Total revenue | $ | 374,145 | $ | 191,809 | |||
Adjusted EBITDA | $ | 80,894 | $ | 21,705 | |||
Average active hydraulic fracturing horsepower | 630,000 | 445,000 | |||||
Total fracturing stages | 4,652 | 3,349 | |||||
Average active wireline trucks | 67 | 66 | |||||
Average active pumpdown units | 72 | 49 | |||||
During the first quarter of 2018, all of our core Completion Services businesses continued to grow as we capitalized on improving customer activity levels, increased utilization on an expanding asset base and captured higher pricing. Our alignment with customers with significant well inventories helped us navigate the seasonality with minimal impact on our results. Although we experienced logistical challenges, we overcame them with minimal disruptions to our fracturing business due to our strategy of partnering with quality sand suppliers and then supplementing that committed capacity with spot purchasing. Building on that strategy, we do not currently expect significant issues in managing logistics or sand supply in the coming quarters. Our fracturing business benefited from a full quarter of utilization of our fourteenth frac fleet delivered in late 2017, and we also took delivery of a new-build horizontal frac fleet consisting of new Tier II pumps with refurbished ancillary equipment at the end of the quarter. In our cased-hole wireline and pumping business, despite pockets of weather and customer-related downtime associated with sand delivery delays, we experienced another quarter of strong customer demand and higher pricing that generated both revenue and Adjusted EBITDA growth.
Well Construction and Intervention Services
The core services provided through our Well Construction and Intervention Services segment includes cementing, coiled tubing and directional drilling services. During the first quarter of 2018, we decided to exit our directional drilling business and we are in the process of selling the related assets and inventory. The majority of revenue for this segment is generated by our cementing business.
During the first quarter of 2018, our cementing business deployed, on average, approximately 71 cementing units out of our current fleet of 118 units. In our coiled tubing business, we deployed, on average, 17 coiled tubing units out of our current fleet of approximately 44 units. Our deployed assets may not be utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.
Management evaluates the operational performance of our Well Construction and Intervention Services segment and allocates resources primarily based on Adjusted EBITDA because management believes that Adjusted EBITDA provides important information about the activity and profitability of our lines of business within this segment. Adjusted EBITDA is computed as total earnings (loss) before net interest expense, income taxes, depreciation and amortization, other income (expense), net, net gain or loss on disposal of assets, acquisition-related costs, and non-routine items.
For the quarter ended March 31, 2018, revenue from our Well Construction and Intervention Services segment was $87.4 million, representing approximately 15.8% of our total revenue, compared with revenue of $56.3 million for the quarter ended December 31, 2017, which represents a 55.3% quarter-over-quarter increase. Adjusted EBITDA from this segment for the quarter ended March 31, 2018, was $16.0 million, compared with $9.8 million of Adjusted EBITDA for the quarter ended December 31, 2017. Please also read Note 7 - Segment Information in Part I, Item 1 “Financial Statements” of
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this Quarterly Report, for a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure (in thousands) for the three months ended March 31, 2018 and 2017.
Three Months Ended | |||||||
March 31, 2018 | March 31, 2017 | ||||||
Revenue | |||||||
Cementing | $ | 61,548 | $ | 7,503 | |||
Coiled Tubing | 25,788 | 17,758 | |||||
Other | 81 | 858 | |||||
Total revenue | $ | 87,417 | $ | 26,119 | |||
Adjusted EBITDA | $ | 16,001 | $ | 1,037 | |||
Average cementing units | 117 | 35 | |||||
Average active cementing units | 71 | 25 | |||||
Average coiled tubing units | 44 | 44 | |||||
Average active coiled tubing units | 17 | 22 | |||||
In our Well Construction and Intervention Services segment, our first quarter results benefited from a full quarter of operations from O-Tex, which we acquired in November 2017. In our coiled tubing business, demand for large diameter coil has remained strong, and we experienced increases in both utilization and pricing. Average revenue per deployed coiled tubing unit improved by 11.0% in the first quarter, primarily due to increased activity levels. Our large diameter units now account for over 80.0% of the revenue and profitability generated in our coiled tubing business. In our cementing business, despite some early delays, customer activity levels increased throughout the first quarter in the majority of our operating basins. In West Texas, both utilization and pricing of our deployed units increased as we were awarded additional work from both new and existing customers.
Well Support Services
Our Well Support Services segment focuses on post-completion activities at the well site, including rig services, such as workover and plug and abandonment, fluids management services, and special services, including artificial lift applications and other specialty well site services. During the first quarter of 2018, we decided to exit our artificial lift business and we are in the process of selling the related assets and inventory. Additionally, in response to the continued competitive landscape, we have continued to focus on operational rightsizing measures to better align these businesses with current market conditions, which has included closing facilities and idling unproductive equipment. For example, during the fourth quarter of 2017, we divested our Canadian rig services business and during the first quarter of 2018 we exited the condensate hauling business in South Texas. The majority of revenue for this segment is generated by our rig services business, and we consider rig services and fluids management to be the core businesses within this segment.
During the first quarter of 2018, our rig services business deployed, on average, approximately 124 workover rigs per workday out of our average fleet of approximately 357 marketable workover rigs. In our fluids management business, we deployed, on average, approximately 616 fluid services trucks per workday and approximately 1,242 frac tanks per workday out of our estimated average fleets of approximately 1,064 trucks and 3,468 frac tanks, respectively. In our fluids management business, we own 25 private salt water disposal wells for fluids disposal purposes. However, not all of our deployed assets are utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.
For the quarter ended March 31, 2018, revenue from our Well Support Services segment was $91.4 million representing approximately 16.5% of our total revenue, compared with revenue of $92.3 million for the quarter ended December 31, 2017, which represents a 0.9% quarter-over-quarter decrease. Adjusted EBITDA from this segment for the quarter ended March 31, 2018 was $5.1 million, compared with $2.7 million of Adjusted EBITDA for the quarter ended December 31, 2017.
Management evaluates the operation and performance of our Well Support Services segment and allocates resources primarily based on activity levels, specifically rig and trucking hours, as well as Adjusted EBITDA. The following
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table presents revenue, rig and trucking hours for our Well Support Services segment for the three months ended March 31, 2018 and 2017 (dollars in thousands). Please also read Note 7 - Segment Information in Part I, Item 1 “Financial Statements” of this Quarterly Report, for a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure (in thousands) for the three months ended March 31, 2018 and 2017.
Three Months Ended | |||||||
March 31, 2018 | March 31, 2017 | ||||||
Revenue | |||||||
Rig Services | $ | 48,445 | $ | 55,545 | |||
Fluids Management | 31,795 | 29,934 | |||||
Other Special Well Site Services | 11,198 | 10,787 | |||||
Total revenue | $ | 91,438 | $ | 96,266 | |||
Adjusted EBITDA | $ | 5,107 | $ | 3,824 | |||
Average active workover rigs | 140 | 158 | |||||
Total workover rig hours | 92,428 | 96,057 | |||||
Average fluids management trucks | 1,064 | 1,118 | |||||
Average active fluids management trucks | 616 | 631 | |||||
Total fluids management truck hours | 307,002 | 296,443 | |||||
During the first quarter of 2018, Well Support Services segment revenue decreased slightly compared to the prior quarter, primarily due to the loss of revenue from our Canadian rig services business that was divested in the fourth quarter of 2017, and to a lesser extent, our exit from the condensate hauling business in South Texas. The decisions to exit these areas, as well as our directional drilling and artificial lift businesses, reflect our returns focused philosophy of intolerance for underperforming businesses or locations and redeploying capital to achieve higher levels of profitability and targeted returns. As a result of this strategy, overall segment profitability increased by focusing on areas with improving customer demand and higher overall pricing for our services. We exited the quarter with high single digit Adjusted EBITDA margins in this segment, despite the losses associated with our artificial lift business. In our rig services business, we experienced improved activity levels in almost all core operating basins, but weather delays mitigated a portion of the revenue and profitability improvement. Weather delays also impacted our fluids management business; however, we improved both revenue and profitability due to improving activity levels and pricing, primarily in West Texas. We expect performance of our Well Support Services businesses to continue to improve due to our strategy of implementing pricing increases and exiting locations and businesses that do not achieve our targeted returns on investment.
Operating Overview & Strategy
Our results of operations in our core service lines are driven primarily by four interrelated, fluctuating variables: (1) the drilling, completion and production activities of our customers, which is primarily driven by oil and natural gas prices and directly affects the demand for our services; (2) the price we are able to charge for our services, which is primarily driven by the level of demand for our services and the supply of equipment capacity in the market; (3) the cost of products and labor involved in providing our services, and our ability to pass those costs on to our customers; and (4) our activity, or “utilization” levels, and service performance.
Our operating strategy is focused on maintaining high asset utilization levels to maximize revenue generation while controlling cost to gain a competitive advantage and drive returns. We believe that the quality and efficiency of our service execution and aligning with customers who recognize the value that we provide through efficiency gains are central to our efforts to support utilization and grow our business. However, asset utilization is not necessarily indicative of our financial and/or operational performance and should not be given undue reliance. Given the volatile and cyclical nature of activity drivers in the U.S. onshore oilfield services industry, coupled with the varying prices we are able to charge for our services and the cost of providing those services, among other factors, operating margins can fluctuate widely depending on supply and demand for both our services and products and labor at a given point in the cycle.
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Historically, our utilization levels have been highly correlated to U.S. onshore spending by our customers. Generally, as capital spending by our customers increases, drilling, completion and production activity also increases, resulting in increased demand for our services, and therefore more days or hours worked (as the case may be). Conversely, when drilling, completion and production activity levels decline due to lower spending by our customers, we generally provide fewer services, which results in fewer days or hours worked (as the case may be). Additionally, during periods of decreased spending by our customers, we may be required to discount our rates or provide other pricing concessions to remain competitive and support utilization, which negatively impacts our revenue and operating margins. During periods of pricing weakness for our services, we may not be able to reduce our costs accordingly, and our ability to achieve any cost reductions from our suppliers typically lags behind the decline in pricing for our services, which further adversely affects our results. For additional information about factors impacting our business and results of operations, please see “Industry Trends and Outlook” in this Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Management evaluates the performance of our reportable business segments primarily based on Adjusted EBITDA because management believes Adjusted EBITDA provides important information about the activity and profitability of our lines of business within each reportable business segment and aids us in analytical comparisons for purposes of, among other things, efficiently allocating our assets and resources. Our management team also monitors asset utilization, among other factors, for purposes of assessing our overall activity levels and customer demand. However, given the variance in revenue and profitability from job to job, depending on the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed, asset utilization cannot be relied on as indicative of our financial or operating performance.
• For our Completion Services operations, we measure our asset utilization levels primarily by the total number of days that our asset base works on a monthly basis, based on the available working days per month, which excludes scheduled maintenance days. We generally consider an asset to be working such days that it is at or in transit to a job location, regardless of the number of hours worked or whether it generated any revenue during such time.
•In our Well Construction and Intervention Services segment, we measure our asset utilization levels primarily by the total number of days that our asset base works on a monthly basis, based on the available working days per month. In our coiled tubing business, we measure certain asset utilization levels by the hour to better understand measures between daylight and 24-hour operations. Both the financial and operating performance of our coiled tubing and cement units can vary in revenue and profitability from job to job depending on the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed.
•In our Well Support Services operations, we measure activity levels primarily by the number of hours our assets work on a monthly basis, based on the available working days per month.
For additional information, please see “Our Reportable Business Segments” in this Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Industry Trends and Outlook
We face many challenges and risks in the industry in which we operate. Although many factors contributing to these risks are beyond our ability to control, we continuously monitor these risks and have taken steps to mitigate them to the extent practicable. In addition, while we believe that we are well positioned to capitalize on available growth opportunities, we may not be able to achieve our business objectives, and consequently, our results of operations may be adversely affected. Please read the factors described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” in Part I, Financial Information and “Risk Factors” in Part II, Item 1A of this Quarterly Report for additional information about the known material risks that we face.
General Industry Trends
The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including the domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by oil and gas companies to their drilling, completion and workover budgets. The oil and gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity, weather conditions, and other factors that are beyond our control.
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In light of the above, demand for our services tends to be extremely volatile and cyclical, as it is a direct function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the United States. Our customers’ willingness to undertake such activities and expenditures depends largely upon prevailing industry conditions that are influenced by numerous factors which are beyond our control, including, among other things, current and expected future levels of oil and gas prices and the perceived stability and sustainability of those prices, which, in turn, is driven primarily by the supply of, and demand for, oil and gas. Oil and gas prices, and therefore the level of drilling, completion and workover activity by our customers, historically have been extremely volatile and are expected to continue to be highly volatile.
In late 2014, oil prices began a substantial and rapid decline, and the severe weakness continued throughout 2015 and the majority of 2016. As we entered 2016, we experienced a sharp drop in activity across our customer base as operators reacted to further declines in oil prices and the deteriorating onshore drilling rig count. The consequent negative impact on the level of drilling, completion and production activity and capital expenditures by our customers adversely affected the demand for our services throughout the severe industry downturn, which adversely impacted our financial and operational performance. Both crude oil and natural gas prices began to increase modestly and stabilize in late 2016 and have generally remained so, although at levels significantly lower than experienced prior and leading up to the downturn. For example, during February 2016, NYMEX crude oil prices reached their lowest levels since 2009, declining to as low as $26.21 per barrel. Crude oil prices have rebounded from the lows set in early 2016 and, during the first quarter of 2018, prices have averaged approximately $63.00 per barrel. Natural gas prices declined significantly in 2009 and have remained depressed relative to pre-2009 levels. Commodity prices continue to be relatively unstable and any declines or perceived sustained weakness impacts the allocation of capital by our customers.
As explained above, sustained weakness in oil and gas prices influences our customers to curtail their operations, reduce their capital expenditures, and request pricing concessions to reduce their operating costs. The demand for drilling, completion and workover services is driven by available investment capital for such activities and in a lower oil and gas price environment, demand for service and maintenance generally decreases as oil and gas producers decrease their activity and expenditures. Because the type of services that we offer can be easily “started” and “stopped,” and oil and gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we typically experience a more rapid decline in demand for our services compared with demand for other types of energy services. A prolonged low level of customer activity, such as we experienced in 2015 and through most of 2016, could adversely affect our financial condition and results of operations.
Competition and Demand for Our Services
We operate in highly competitive areas of the oilfield services industry with significant potential for excess capacity. With respect to all of our core services, the equipment can be moved with relative ease from one region to another in response to changes in levels of activity and market conditions, which has in the past and likely will result in an oversupply of equipment in high activity areas. Utilization and pricing for our services have in the past been negatively affected by increases in supply relative to demand in our core operating areas and geographic markets.
Additionally, the demand for our services depends primarily on the level of spending by oil and gas companies for drilling, completion and production activities, which is affected by short-term and long-term trends in oil and natural gas prices and numerous other factors over which we have no control. Severe declines and sustained weakness and volatility in commodity prices over the course of 2015, and for most of 2016, and the consequent negative impact on the level of drilling, completion and production activity and capital expenditures by our customers, adversely affected the demand for our services. This, in turn, negatively impacted our ability to maintain adequate utilization of our asset base and to negotiate pricing at levels generating sufficient margins. The impact to our financial and operational performance ultimately led to the Company’s Chapter 11 Proceeding (see Note 2 - Chapter 11 Proceeding and Emergence in Part I, Item 1 “Financial Statements” of this Quarterly Report).
Our revenues and profitability are directly affected by changes in utilization and pricing levels for our services, which fluctuate in direct response to changes in the level of drilling, completion and production activity by our customers. Pressure on pricing for our services, including due to competition and industry and/or economic conditions, may impact, among other things, our ability to maintain utilization and profitability. During periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our results. Furthermore, even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset any rising costs. Also, we may not be able to successfully increase prices without adversely affecting our utilization levels. The inability to maintain our utilization and pricing levels, or to increase our prices as costs increase, could have a material adverse effect on our business, financial position and results of operations.
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Our competitors include many large and small energy service companies, including some of the largest integrated oilfield services companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow them to compete more effectively than we can, including by reducing prices for services in our core operating areas. Our major competitors for both our Completion Services and Well Construction and Intervention Services segments include Halliburton, Schlumberger, BJ Services, Keane Group, RPC, Inc., FTS International, Inc., ProPetro Holding Corp., Basic Energy Services, Superior Energy Services, CalFrac Well Services, as well as a significant number of regional, predominantly private businesses. Our major competitors for our Well Support Services include Key Energy Services, Basic Energy Services, Superior Energy Services, Precision, Forbes, Pioneer Energy Services and Ranger Energy Services, as well as a significant number of predominantly private, regional businesses.
Generally, we believe that the principal competitive factors in the markets that we serve are price, technical expertise, equipment capacity, work force capability, safety record, reputation and experience. Although we believe our customers consider all of these factors, price is often the primary factor in determining which service provider is awarded work, particularly during times of weak commodity prices such as those we experienced from late 2014 through the majority of 2016. Throughout this severe, prolonged downturn for our industry, our customer base demonstrated a more intense focus and placed a higher priority on receiving the lowest service cost pricing possible. Additionally, projects for certain of our core service lines are often awarded on a bid basis, which tends to further increase competition based primarily on price. During the downturn and even during healthier environments, our utilization and pricing levels are negatively impacted by predatory pricing from competitors who elect to operate at negative margins.
During healthier market conditions, we believe many of our customers choose to work with us based on the safety, performance and quality of our crews, equipment and services, although even then, we must be competitive in our pricing. We seek to differentiate ourselves from our major competitors by our operating philosophy, which is focused on delivering the highest quality customer service and equipment, coupled with superior execution and operating efficiency. As part of this strategy, we target high volume, high efficiency customers with service intensive, 24-hour work, which is where we believe we can differentiate our services from those of our competitors.
Current Market Conditions and Outlook
We are actively monitoring the market and managing our business in line with demand for services, and we try to make adjustments as necessary to effectively respond to changes in market conditions. We are taking a measured approach to asset deployment, balancing our view of customer demand with a focus on generating positive returns for our shareholders. Our top priorities remain to drive revenue by maximizing utilization, to improve margins through cost controls, protect and grow our market share by focusing on the quality and efficiency of our service execution, and to ensure that we are strategically positioned to capitalize on continued market improvement.
Completion Services Outlook
As we move through the second quarter of 2018, based on indicated customer demand and certain market factors, such as rig count and the number of well permits, we currently expect that our Completion Services segment will continue to experience strong activity levels through the end of 2018. Based on existing customer demand in our fracturing business, we are planning to deploy two refurbished horizontal frac fleets to dedicated customers in the second quarter of 2018, which would result in us exiting the second quarter with approximately 740,000 HHP deployed, consisting of seventeen horizontal and two vertical frac fleets. We also are planning to deploy another refurbished horizontal frac fleet early in the third quarter of 2018. Based on market conditions and indications of continued customer demand, we currently anticipate redeploying the remainder of our approximately 120,000 stacked HHP in three horizontal fracturing fleets later in the year, which would result in us exiting 2018 with approximately 900,000 HHP deployed. However, whether we deploy those remaining fleets at all during 2018 and the ultimate timing of doing so depends on customer demand and market conditions. We currently expect to redeploy additional wireline trucks each quarter throughout 2018, contingent upon our ability to recruit and train sufficient additional personnel to service our operations. Additionally, in our pumping business, based on the full utilization of our fleet and demand from existing customers, we currently expect to deploy additional repurposed frac pumps and new-build pumping units into service throughout the remainder of 2018.
On March 8, 2018, the President issued two Proclamations directing the imposition, effective March 23, 2018, of ad valorem tariffs of 25% on certain imported steel products and 10% on certain imported aluminum products from all countries, with the exception of Canada and Mexico. Subsequently, on March 22, 2018, the President issued two additional Proclamations that exempted, in addition to Canada and Mexico, several additional countries from the remedial tariff measures, as follows: (i) Argentina; (ii) Australia; (iii) Brazil; (iv) the 28 member countries of the European Union; and (v) South Korea. In Proclamations issued on April 30, 2018, the President: (i) permanently exempted South Korea from the imposition of tariffs
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on imported steel, while allowing tariffs to be imposed on imported aluminum; (ii) extended the steel and aluminum tariff exemptions for Argentina, Australia, and Brazil indefinitely to allow for continued negotiations; and (iii) extended the steel and aluminum tariff exemptions for Canada, Mexico, and the 28 member countries of the European Union to allow for continued negotiations, but only through May 31, 2018. In addition to possible country-based exemptions, the United States has established a protocol whereby individuals or entities using any of the affected steel or aluminum products in business activities, such as manufacturing, may request the exclusion of individual products from the imposition of tariffs.
As noted above, our R&T department is primarily engaged in the engineering and production of certain parts and components, such as perforating guns and addressable switches, which are used in the completion process. Certain of these items, particularly perforating guns, are manufactured using imported steel tubing, which is subject to a 25% tariff. While we maintain steel inventories, we expect that, depending on the ultimate outcome of the country exemption and product exclusion processes described above, our raw material costs will increase and result in corresponding increases in the price of our finished goods. Further, in addition to the products manufactured by our R&T department, pricing of other high steel content products used in conjunction with our fracturing and coiled tubing operations, specifically power ends, fluid ends, treating iron and coiled tubing strings, may also increase as we expect the manufacturers of such goods to pass along the net effect the tariffs have on the cost of manufacturing such goods.
Well Construction and Intervention Services Outlook
As we move through the second quarter of 2018, we currently expect that our Well Construction and Intervention Services segment will continue to experience improving activity levels through 2018 due to increased drilling and completion activity and greater demand for large volumes of cement due to longer laterals. In our cementing business, we will continue to focus on increasing utilization and pricing by growing our exposure to the primary cementing market in all operating basins and strengthening our position in the remedial market in the Mid-Continent and the Rocky Mountains. As a result of the loss of a major customer in the Northeast due to consolidation in the E&P industry, we are considering the transfer of pumping assets into higher margin basins to strengthen our market leading position and to capture more cementing work. Operating out of our new facility in Pecos, Texas, we are activating more equipment and investing in infrastructure to support more long string work as we seek to grow market share in the Delaware Basin. Contingent on our ability to source skilled labor in West Texas, we plan to add several pumping units back into service throughout the remainder of 2018. In our coiled tubing business, we plan to take delivery of two new-build, large diameter coiled tubing units during the second quarter of 2018, which we expect to deploy in West Texas to dedicated customers at premium pricing.
Well Support Services Outlook
As we move through the second quarter of 2018, a period with increased daylight hours, we expect that our Well Support Services segment will experience higher activity levels. Additionally, higher oil prices and enhanced workover economics have encouraged many of our customers to allocate additional capital towards well workover and maintenance activities, which we expect to result in higher utilization, greater pricing leverage and improved profitability. We expect recent price increases implemented late in the first quarter of 2018 with customers in our most active operating basins to improve profitability in the second quarter of 2018. In our rig services business, we expect to continue to allocate resources, specifically our refurbished workover rigs, to customers that value our track record of superior quality of service and safety. In our fluids management business, we expect to allocate additional assets into areas with strong fluids demand such as West Texas and the Mid-Continent. However, we are likely to continue to deal with skilled labor shortages in almost every operating basin and thus expect to continue increasing our rates commensurate with our rising cost structure. We continue to be encouraged by the improvement of our Well Support Services segment, and our primary goal remains to align ourselves with customers that value our ability to safely deliver superior service quality and to increase segment profitability and returns.
For additional information, please see “Liquidity and Capital Resources” and “Reportable Segments” in this Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in addition to “Cautionary Note Regarding Forward-Looking Statements” in Part I, Financial Information and “Risk Factors” in Part II, Item 1A of this Quarterly Report.
Results of Operations
The following is a comparison of our results of operations for the three months ended March 31, 2018 compared to the three months ended March 31, 2017. The results for the Predecessor on January 1, 2017 reflect solely the impact of the application of fresh start accounting on that date and are therefore not included in the discussion of results of operations below.
Results for the Three Months Ended March 31, 2018 Compared to the Three Months Ended March 31, 2017
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The following table summarizes the change in our results of operations for the three months ended March 31, 2018 when compared to the three months ended March 31, 2017 (in thousands):
Three Months Ended March 31, 2018 | Three Months Ended March 31, 2017 | $ Change | ||||||||||
Completion Services: | ||||||||||||
Revenue | $ | 374,145 | $ | 191,809 | $ | 182,336 | ||||||
Operating income | $ | 57,806 | $ | 10,845 | $ | 46,961 | ||||||
Well Construction and Intervention Services: | ||||||||||||
Revenue | $ | 87,417 | $ | 26,119 | $ | 61,298 | ||||||
Operating income (loss) | $ | 5,460 | $ | (535 | ) | $ | 5,995 | |||||
Well Support Services: | ||||||||||||
Revenue | $ | 91,438 | $ | 96,266 | $ | (4,828 | ) | |||||
Operating loss | $ | (8,834 | ) | $ | (8,233 | ) | $ | (601 | ) | |||
Corporate / Elimination: | ||||||||||||
Revenue | $ | — | $ | — | $ | — | ||||||
Operating loss | $ | (34,090 | ) | $ | (38,485 | ) | $ | 4,395 | ||||
Combined: | ||||||||||||
Revenue | $ | 553,000 | $ | 314,194 | $ | 238,806 | ||||||
Costs and expenses: | ||||||||||||
Direct costs | 418,997 | 261,743 | 157,254 | |||||||||
Selling, general and administrative expenses | 65,935 | 62,092 | 3,843 | |||||||||
Research and development | 1,872 | 1,217 | 655 | |||||||||
Depreciation and amortization | 46,343 | 31,606 | 14,737 | |||||||||
Gain on disposal of assets | (489 | ) | (6,056 | ) | 5,567 | |||||||
Operating income (loss) | 20,342 | (36,408 | ) | 56,750 | ||||||||
Other income (expense): | ||||||||||||
Interest expense, net | (428 | ) | (691 | ) | 263 | |||||||
Other income (expense), net | 620 | 1,562 | (942 | ) | ||||||||
Total other income (expense) | 192 | 871 | (679 | ) | ||||||||
Income (loss) before income taxes | 20,534 | (35,537 | ) | 56,071 | ||||||||
Income tax benefit | (60 | ) | (3,236 | ) | 3,176 | |||||||
Net income (loss) | $ | 20,594 | $ | (32,301 | ) | $ | 52,895 | |||||
Revenue
Revenue increased $238.8 million, or 76.0%, to $553.0 million for the three months ended March 31, 2018, as compared to $314.2 million for the three months ended March 31, 2017. The increase in revenue was primarily due to (i) an increase of $182.3 million in our Completion Services segment as a result of our expanded fracturing services asset base, as well as the strong demand for all of our completion services, which resulted in improved utilization and pricing , (ii) an increase of $61.3 million in our Well Construction and Intervention Services segment as a result of (a) an increase in cementing revenue due to our expanded business with the acquisition of O-Tex Holdings, Inc. ("O-Tex") during the fourth quarter of 2017 and (b) continued strong demand for our Well Construction and Intervention Services, which resulted in improved utilization and pricing across our asset bases and (iii) a decrease of $4.8 million in our Well Support Services segment primarily as a result of the divestiture of our Canadian rig services business in the fourth quarter of 2017.
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Direct Costs
Direct costs increased $157.3 million, or 60.1% to $419.0 million for the three months ended March 31, 2018, compared to $261.7 million for the three months ended March 31, 2017. The increase in direct costs was primarily due to the increased revenue from our Completion Services and Well Construction and Intervention Services segments. Revenue has been positively impacted by increased utilization levels across our Completion Services segment and from our expanded cementing business with the acquisition of O-Tex.
As a percentage of revenue, direct costs decreased to 75.8% for the three months ended March 31, 2018, as compared to 83.3% for the three months ended March 31, 2017. The decrease was primarily due to substantially improved pricing for our services due to the more favorable market conditions resulting from the increase in commodity prices.
Selling, General and Administrative Expenses (“SG&A”)
SG&A increased $3.8 million, or 6.2%, to $65.9 million for the three months ended March 31, 2018, as compared to $62.1 million for the three months ended March 31, 2017. The increase in SG&A was primarily due to (i) a $7.5 million increase in employee related costs (excluding O-Tex) due to the overall growth of our business, (ii) a $4.2 million increase in severance expense and accelerated equity vesting associated with the departure of an executive officer and (iii) an incremental $2.7 million increase in SG&A expenses as a result of the acquisition of O-Tex, offset by a reduction in share based compensation expense of $12.4 million primarily related to an accelerated vesting in the first quarter of 2017.
Depreciation and Amortization Expense (“D&A”)
D&A increased $14.7 million, or 46.6%, to $46.3 million for the three months ended March 31, 2018, as compared to $31.6 million for the three months ended March 31, 2017. The increase in D&A was primarily the result of increased capital expenditures associated with equipment placed into service after the first quarter of 2017 and the integration of the acquired O-Tex asset base in the fourth quarter of 2017.
Interest Expense
Interest expense decreased $0.3 million, or 38.1% to $0.4 million for the three months ended March 31, 2018, as compared to $0.7 million for the three months ended March 31, 2017. The decrease is primarily due to the expiration of our capital leases during 2017.
Income Taxes
We recorded a tax benefit of $0.1 million for the three months ended March 31, 2018, at a negative effective rate of (0.2%), compared to a tax benefit of $3.2 million for the comparable prior year period, at an effective rate of 9.1%. For the three months ended March 31, 2018, before the effect of additional allowed refund claims, we recorded income taxes at an estimated effective tax rate of approximately 1.0%. The decrease in the effective tax rate, and the resulting effective tax rate below the expected statutory rate, was primarily due to the existence, and adjustment of our valuation allowance applied against certain deferred tax assets, including net operating loss carryforwards.
Liquidity and Capital Resources
Sources of Liquidity and Capital Resources
Our primary uses of cash are for operating costs and expenditures and capital expenditures. The oilfield services business is capital-intensive, requiring significant investment to maintain, upgrade and purchase equipment to meet our customers’ needs and industry demand. Our capital requirements consist primarily of:
• | growth capital expenditures, which are capital expenditures made to acquire additional equipment and other assets, increase our service lines, or advance other strategic initiatives for the purpose of growing our business; and |
• | maintenance capital expenditures related to our existing equipment, such as refurbishment and other activities to extend the useful life of partially or fully depreciated assets. |
Our primary sources of liquidity have historically included, and we have funded our capital expenditures with, cash flows from operations, proceeds from public offerings of our common stock and borrowings under debt facilities. Our ability to generate future cash flows is subject to a number of variables, many of which are outside of our control, including the drilling, completion and production activity by our customers, which is highly dependent on oil and gas prices. See Part I,
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Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Industry Trends and Outlook” for additional discussion of certain factors that impact our results and the market challenges within our industry. Please also read “-Financial Condition and Cash Flows” below for information about net cash provided by or used in our operating, investing and financing activities.
On January 6, 2017, we entered into the Prior Credit Facility with PNC Bank, National Association, as administrative agent (the “Prior Agent”), which was subsequently amended and restated in full on May 4, 2017, with the Prior Agent and the lenders party thereto. On May 1, 2018, the Prior Credit Facility was discharged and canceled and we entered into a new asset-based revolving credit agreement (the “New Credit Facility”), with JPMorgan Chase Bank, N.A., as administrative agent. As of May 4, 2018, we had $325.5 million of available borrowing capacity under our New Credit Facility after taking into consideration our current outstanding letters of credit of approximately $21.7 million. Under the terms of our New Credit Facility, the borrowing base is subject to monthly adjustments based on current levels of accounts receivable and inventory. For additional information about the New Credit Facility, please see “Description of our Indebtedness” below and Note 3 - Debt in Part I, Item 1 “Financial Statements” of this Quarterly Report.
As of March 31, 2018, we had a cash balance of $88.0 million and no borrowings drawn on our Prior Credit Facility, resulting in total liquidity of $266.5 million. As of May 4, 2018, we had a cash balance of approximately $69.9 million and no borrowings drawn on our New Credit Facility, resulting in total liquidity of approximately $395.4 million.
Capital expenditures totaled $63.0 million in the first quarter of 2018, primarily pertaining to the maintenance of deployed equipment, the refurbishment of existing stacked equipment in preparation for redeployment later in the year and related reactivation costs, and building new equipment for deployment in our core service lines. Based on current market conditions and customer demand, we continue to expect 2018 capital expenditures to range between approximately $430.0 million and $450.0 million. The majority of our 2018 capital expenditure program is currently planned to be used for the full refurbishment of all of our remaining stacked fracturing fleets and related reactivation costs, which we expect to fully redeploy by year-end, the refurbishment and redeployment of stacked equipment for most of our other core service lines, the manufacturing and deployment of new-build equipment primarily in our Completion Services segment, and the ongoing maintenance of our active, deployed equipment across our asset base. However, if current market conditions soften, we may reevaluate our current plan with respect to equipment reactivation and deployment .
Given continued indications of customer demand, coupled with current market factors, including increasing U.S. drilling rig count, stable commodity prices, and the continued shortage of available fracturing equipment, we have been particularly focused on redeploying our stacked frac fleets. We are continuing to invest in upgrading and standardizing our equipment concurrent with our reactivation efforts, which among other benefits, is expected to increase the operating life of the equipment and lower the overall cost of ownership over time. During the first quarter of 2018, we deployed a second new-build frac fleet consisting of new-build Tier II frac pumps and refurbished ancillary equipment, totaling 40,000 HHP. Accordingly, we exited the first quarter of 2018 with approximately 655,000 HHP deployed consisting of fifteen horizontal and two vertical frac fleets. Our typical horizontal fleet size consists of 20 pumps, or 40,000 HHP, and our typical vertical fleet size consists of 10 pumps, or 20,000 HHP. We currently plan to deploy three additional refurbished horizontal frac fleets, consisting of 40,000 HHP each, from May through July with identified dedicated customers. Additionally, we currently anticipate redeploying the remainder of our approximately 120,000 stacked HHP in three horizontal fracturing fleets later in the year. However, whether we deploy those remaining fleets at all during 2018 and the ultimate timing of doing so depends on customer demand and market conditions. The refurbishment of the last six fleets has an average estimated capital cost of approximately $24.0 million per 40,000 HHP horizontal (or horizontal equivalent) frac fleet. Our remaining stacked HHP represents our oldest stacked equipment, and thus these fleets are the most expensive to refurbish and redeploy. This estimated capital cost is inclusive of the pump refurbishment costs and the ancillary equipment necessary for future redeployment. The estimated capital cost to redeploy the remainder of our stacked HHP is inherently uncertain until the refurbishment process begins. Although we believe that approximately $24.0 million per horizontal equivalent frac fleet on average is a reasonable estimate, the actual capital cost to redeploy the remainder of our stacked HHP may exceed our current estimates, particularly since the remaining fleets are expected to require more intensity due to their condition. Additionally, we currently expect a portion of our capital expenditure program for 2018 to consist of the purchase of advanced auxiliary well-site equipment and additional units within our other core service lines. However, if current market conditions soften, we may reevaluate our current plan with respect to equipment reactivation and deployment across all of our core service lines.
We expect to fund our 2018 capital expenditure program with cash flows from operations as well as borrowings under our New Credit Facility. The amount of indebtedness we have outstanding could limit our ability to finance future growth and could adversely affect our operations and financial condition.
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Based on our existing operating performance, we currently believe that our cash flows from operations, cash on hand and borrowings under our New Credit Facility will be sufficient to meet our operational and capital expenditure requirements over the next twelve months.
Financial Condition and Cash Flows
The net cash provided by or used in our operating, investing and financing activities is summarized below (in thousands):
Three Months Ended March 31, 2018 | Three Months Ended March 31, 2017 | ||||||||
Cash provided by (used in): | |||||||||
Operating activities | $ | 35,656 | $ | (77,902 | ) | ||||
Investing activities | (59,387 | ) | 16,615 | ||||||
Financing activities | (2,267 | ) | (3,979 | ) | |||||
Effect of exchange rate on cash | 88 | (858 | ) | ||||||
Change in cash and cash equivalents | $ | (25,910 | ) | $ | (66,124 | ) | |||
Cash Provided by Operating Activities
Net cash provided by operating activities was $35.7 million for the three months ended March 31, 2018. The inflow of cash was primarily related to net income of $20.6 million, adjustments for non-cash items of $53.7 million, $3.6 million related to a federal income tax refund and positive changes in other operating assets and liabilities primarily related to prepaid expenses and accounts payable. These cash inflows were offset by $63.3 million of increased investment in working capital (accounts receivable, inventory and payroll related costs and accrued expenses) as a result of the increase in demand for our services primarily from our Completion Services and Well Construction and Intervention Services segments for the first three months of 2018.
Net cash used in operating activities was $77.9 million for the three months ended March 31, 2017. The use of cash was primarily related to (i) a net loss of $32.3 million and (ii) a $94.5 million negative change in accounts receivable primarily from the temporary increase in days sales outstanding as a result of our migration to our new SAP enterprise resource planning system during the first quarter of 2017. These cash outflows were partially offset by (i) adjustments for non-cash items of $43.3 million and (ii) positive changes in other operating assets and liabilities, excluding accounts receivable.
Cash Used in Investing Activities
Net cash used in investing activities was $59.4 million for the three months ended March 31, 2018. The use of cash was related to $63.0 million of capital expenditures primarily pertaining to the refurbishment of stacked equipment and the construction of new-build frac pumps and refurbished ancillary equipment, partially offset by $3.6 million of proceeds from the disposal of property, plant and equipment and the divestiture of our non-core service lines.
Net cash provided by investing activities was $16.6 million for the three months ended March 31, 2017. The inflow of cash was primarily related to $28.2 million of proceeds from the disposal of property, plant and equipment and the divestiture of our non-core service lines, offset by $11.6 million of capital expenditures primarily pertaining to our deployed equipment and refurbishment of existing stacked equipment in preparation for redeployment.
Cash Provided by Financing Activities
Net cash used by financing activities was $2.3 million for the three months ended March 31, 2018. The cash used was primarily related to $2.2 million of employee tax withholding on restricted stock vesting.
Net cash used by financing activities was $4.0 million for the three months ended March 31, 2017. The cash used was primarily related to $3.8 million of employee tax withholding on restricted stock vesting.
Description of our Indebtedness
New Credit Facility
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The Company and certain of its subsidiaries (the “Borrowers”) entered into that certain Asset-Based Revolving Credit Agreement with, among others, JPMorgan Chase Bank, N.A., as administrative agent (the “Agent”), on the May 1, 2018 (the “New Credit Facility”).
The New Credit Facility allows the Borrowers to incur revolving loans in an aggregate amount up to the lesser of (a) $400.0 million or (b) a borrowing base (the “Loan Cap”), which borrowing base is based upon the value of the Borrowers’ accounts receivable, inventory and restricted cash, subject to eligibility criteria and customary reserves which may be modified in the Agent’s permitted discretion.
The New Credit Facility also provides for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the New Credit Facility is May 1, 2023.
If at any time the amount of loans and other extensions of credit outstanding under the New Credit Facility exceed the borrowing base, the Borrowers may be required, among other things, to prepay outstanding loans immediately.
The Borrowers’ obligations under the New Credit Facility are secured by liens on a substantial portion of the Borrowers’ personal property, subject to certain exclusions and limitations. Upon the occurrence of certain events, additional collateral, including a portion of the Borrowers’ real properties, may also be required to be pledged. Each of the Borrowers is jointly and severally liable for the obligations of the other Borrowers under the New Credit Facility.
At the Borrowers’ election, interest on borrowings under the New Credit Facility will be determined by reference to either LIBOR plus an applicable margin of between 1.50% and 2.00% or an “alternate base rate” plus an applicable margin of between 0.50% and 1.00%, in each case based on the Company’s total leverage ratio. Interest will be payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans and, in the case of an interest period longer than three months, quarterly, upon any prepayment and at final maturity. The Borrowers will also be required to pay a fee on the unused portion of the New Credit Facility equal to ((i) 0.50% per annum if average utilization is less than or equal to 25% or (ii) 0.375% per annum if average utilization is greater than 25%, in each case payable quarterly in arrears to the Agent.
The New Credit Facility contains covenants that limit the Borrowers’ ability to incur additional indebtedness, grant liens, make loans, make acquisitions or investments, make distributions, merge into or consolidate with other persons, or engage in certain asset dispositions.
The New Credit Facility also contains a financial covenant which requires the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 upon the occurrence of an event of default or on any date upon which the excess availability is less than the greater of (x) 12.5% of the lesser of the Loan Cap and (y) $30.0 million.
The fixed charge coverage ratio is generally defined in the New Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.
Prior Credit Facility
The Company and certain of its subsidiaries (the “Prior Borrowers”) entered into the Prior Credit Facility on the January 6, 2017, which was subsequently amended and restated in full on May 4, 2017. The Prior Credit Facility was canceled and discharged on May 1, 2018.
The Prior Credit Facility allowed the Prior Borrowers to incur revolving loans in an aggregate amount up to the lesser of (a) $200.0 million or (b) a borrowing base, which borrowing base was based upon the value of the Prior Borrowers’ accounts receivable and inventory, subject to eligibility criteria and customary reserves which may have been modified in the Prior Agent’s permitted discretion.
The Prior Credit Facility also provided for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the Prior Credit Facility was May 4, 2022.
If at any time the amount of loans and other extensions of credit outstanding under the Prior Credit Facility exceeded the borrowing base, the Prior Borrowers may have been required, among other things, to prepay outstanding loans immediately.
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The Prior Borrowers’ obligations under the Prior Credit Facility were secured by liens on a substantial portion of the Prior Borrowers’ personal property, subject to certain exclusions and limitations. Upon the occurrence of certain events, additional collateral, including a portion of the Prior Borrowers’ real properties, may also may have been required to be pledged. Each of the Prior Borrowers was jointly and severally liable for the obligations of the other Prior Borrowers under the Prior Credit Facility.
At the Prior Borrowers’ election, interest on borrowings under the Prior Credit Facility would have been determined by reference to either LIBOR plus an applicable margin of 2.0% or an “alternate base rate” plus an applicable margin of 1.0%. Beginning after the fiscal month ending on or about September 30, 2017, these margins were subject to a monthly step-up of 0.25% in the event that average excess availability under the Prior Credit Facility was less than 37.5% of the total commitment, and a monthly step-down of 0.25% in the event that average excess availability under the Prior Credit Facility was equal to or greater than 62.5% of the total commitment. Interest was payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans. The Prior Borrowers were required to pay a fee on the unused portion of the Prior Credit Facility equal to (i) 0.75% in the event that utilization was less than 25.0% of the total commitment, (ii) 0.50% in the event that utilization was equal to or greater than 25% of the total commitment but less than 50% of the total commitment and (iii) 0.375% in the event that utilization was equal to or greater than 50% of the total commitment.
The Prior Credit Facility contained covenants that limited the Prior Borrowers’ ability to incur additional indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, make capital expenditures or engage in certain asset dispositions including a sale of all or substantially all of the Company’s assets.
The Prior Credit Facility also contained a financial covenant which required the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 if, as of any month-end, liquidity is less than $40.0 million.
The fixed charge coverage ratio was generally defined in the Prior Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.
Other Matters
Contractual Obligations
Our contractual obligations at March 31, 2018, did not change materially from those disclosed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Contractual Obligations” of our 2017Annual Report.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K, as of March 31, 2018.
Recent Accounting Pronouncements
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). ASU No. 2016-02 seeks to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and by disclosing key information about leasing arrangements. Unlike current U.S. GAAP, which requires only capital leases to be recognized on the balance sheet, ASU No. 2016-02 will require both operating and finance leases to be recognized on the balance sheet. Additionally, the new guidance will require disclosures to help investors and other financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements. The amendments in ASU No. 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We will adopt this new accounting standard on January 1, 2019. We are currently determining the impacts of the new standard on our consolidated financial statements. The approach includes performing a detailed review of our lease portfolio by evaluating our population of leased assets and designing and implementing new processes and controls.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which amends U.S. GAAP by introducing a new impairment model for financial instruments that is based on expected credit losses rather than incurred credit losses. The new impairment
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model applies to most financial assets, including trade accounts receivable. The amendments in ASU 2016-13 are effective for interim and annual reporting periods beginning after December 15, 2019, although it may be adopted one year earlier, and requires a modified retrospective transition approach. We are currently evaluating the impact this standard will have on our results of operations and financial position.
In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory ("ASU 2016-16"), which requires an entity to recognize the income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory, when the transfer occurs. The ASU is effective for the interim and annual reporting periods beginning after December 15, 2017, including interim periods within those fiscal years, and early application is permitted. We adopted this new accounting standard on January 1, 2018. We recognized a cumulative effect adjustment as a reduction to retained earnings of $13.2 million which occurred as a result of the Company's adoption of ASU 2016-16.
In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"), which establishes a one-step process for testing goodwill for a drop in value. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019 and early adoption is permitted. We adopted this new accounting standard on January 1, 2018 and the adoption did not have an impact on our consolidated financial statements.
In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ("ASU 2018-02"), which allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act and requires certain disclosures about stranded tax effects. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently evaluating the impact of this standard on our consolidated financial statements.
In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118, ("ASU 2018-05"), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (the Tax Act) pursuant to Staff Accounting Bulletin No. 18, which allows companies to complete the accounting under ASC 740 within a one-year measurement period from the Tax Act enactment date. This standard is effective upon issuance. We are currently evaluating the impact of this standard on our consolidated financial statements.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
As of March 31, 2018, there have been no material changes in market risk from the information provided in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” or “Quantitative and Qualitative Disclosures About Market Risk” in our 2017 Annual Report.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that the information required to be disclosed by us in our reports that we file or submit 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 principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2018.
Changes in Internal Controls Over Financial Reporting.
There were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarterly period ended March 31, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are, from time to time, subject to various legal proceedings and claims incidental to or arising in the ordinary course of our business. Our management does not presently expect the outcome in any known legal proceedings, individually or collectively, to have a material adverse effect on our consolidated financial condition or results of operations.
U.S. Department of Justice Criminal Investigation into Pre-Merger Incident
There is a pending criminal investigation led by the Department of Justice in connection with a fatality that occurred at a facility we own in Williston, North Dakota on October 3, 2014 prior to our acquisition of such facility in connection with the Nabors Merger. We are cooperating fully with the investigation, and expect to continue to do so. At this time, we cannot predict the outcome of the investigation.
ITEM 1A. RISK FACTORS
In addition to the information set forth in this Quarterly Report, including under the section titled “Cautionary Note Regarding Forward-Looking Statements,” in Part I, Item 1 “Financial Information,” you should carefully consider the information set forth in Item 1A “Risk Factors” in our 2017 Annual Report, which is incorporated by reference herein, for a detailed discussion of known material factors which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table summarizes share repurchase activity for the three months ended March 31, 2018:
Period | Total Number of Shares Purchased (a) | Average Price Paid Per Share | Total Number of Shares Purchased as Part of Publicly Announced Program | Maximum Number of Shares that may yet be Purchased Under Such Program | ||||||||||
January 1 - January 31 | — | — | $ | — | — | — | ||||||||
February 1 - February 28 | 61,854 | $ | 28.49 | — | — | |||||||||
March 1 - March 31 | 17,364 | $ | 25.04 | — | — | |||||||||
(a) Represents shares that were withheld by the Company to satisfy tax withholding obligations of employees that arose upon the vesting of restricted shares. The value of such shares is based on the closing price of our common shares on the vesting date.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
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ITEM 6. EXHIBITS
The exhibits required to be filed or furnished by Item 601 of Regulation S-K are listed below.
Exhibit No. | Description of Exhibit. | ||
2.1 | |||
3.1 | |||
3.2 | |||
3.3 | |||
10.1 | |||
10.2 | |||
* 31.1 | |||
* 31.2 | |||
** 32.1 | |||
** 32.2 | |||
*§101.INS | XBRL Instance Document | ||
*§101.SCH | XBRL Taxonomy Extension Schema Document | ||
* §101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | ||
* §101.LAB | XBRL Taxonomy Extension Label Linkbase Document | ||
* §101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | ||
* §101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | ||
* | Filed herewith |
** | Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K. |
+ | Management contract or any compensatory plan, contract or arrangement. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
C&J Energy Services, Inc. | ||||||||
Date: | May 8, 2018 | By: | /s/ Donald J. Gawick | |||||
Donald J. Gawick | ||||||||
Chief Executive Officer, President and Director | ||||||||
(Principal Executive Officer) | ||||||||
By: | /s/ Michael S. Galvan | |||||||
Michael S. Galvan | ||||||||
Interim Chief Financial Officer and Chief Accounting Officer | ||||||||
(Principal Financial Officer and Principal Accounting Officer) | ||||||||
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EXHIBIT INDEX
Exhibit No. | Description of Exhibit. | ||
2.1 | |||
3.1 | |||
3.2 | |||
3.3 | |||
10.1 | |||
10.2 | |||
* 31.1 | |||
* 31.2 | |||
** 32.1 | |||
** 32.2 | |||
*§101.INS | XBRL Instance Document | ||
*§101.SCH | XBRL Taxonomy Extension Schema Document | ||
* §101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | ||
* §101.LAB | XBRL Taxonomy Extension Label Linkbase Document | ||
* §101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | ||
* §101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | ||
* | Filed herewith |
** | Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K. |
+ | Management contract or any compensatory plan, contract or arrangement. |
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