KEY ENERGY SERVICES INC - FORM 10-Q

Attached files

Attached files

Stock widget

Investing forum

KEY ENERGY SERVICES INC Reports

file	filename
EX-32 - EXHIBIT 32 - KEY ENERGY SERVICES INC	kegex326302018.htm
EX-31.2 - EXHIBIT 31.2 - KEY ENERGY SERVICES INC	kegex3126302018.htm
EX-31.1 - EXHIBIT 31.1 - KEY ENERGY SERVICES INC	kegex3116302018.htm

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________

Form 10-Q

_____________________________________________

(Mark One)



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

For the Quarterly Period Ended June 30, 2018



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-08038

_____________________________________________

KEY ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)

_____________________________________________



Delaware		04-2648081
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1301 McKinney Street, Suite 1800, Houston, Texas		77010
(Address of principal executive offices)		(Zip Code)

(713) 651-4300

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year, if changed since last report)

____________________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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	¨	Accelerated filer	ý

Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

		Emerging growth company	¨

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

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

As of August 3, 2018, the number of outstanding shares of common stock of the registrant was 20,244,545.

Table of Contents

KEY ENERGY SERVICES, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2018



Part I — Financial Information

Item 1.	Financial Statements	4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32

Item 4.	Controls and Procedures	32

Part II — Other Information

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33

Item 3.	Defaults Upon Senior Securities	33

Item 4.	Mine Safety Disclosures	33

Item 5.	Other Information	33

Item 6.	Exhibits	33

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These forward-looking statements are based on our current expectations, estimates and projections and management’s beliefs and assumptions concerning future events and financial trends affecting our financial condition and results of operations. In some cases, you can identify these statements by terminology such as “may,” “will,” “should,” “predicts,” “expects,” “believes,” “anticipates,” “projects,” “potential” or “continue” or the negative of such terms and other comparable terminology. These statements are only predictions and are subject to substantial risks and uncertainties and are not guarantees of performance. Future actions, events and conditions and future results of operations may differ materially from those expressed in these statements. In evaluating those statements, you should carefully consider the information above as well as the risks outlined in Part I “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017, Part II, “Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the three months ended March 31, 2018 and in the other reports we file with the Securities and Exchange Commission.

We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date of this report except as required by law. All of our written and oral forward-looking statements are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements.

Important factors that may affect our expectations, estimates or projections include, but are not limited to, the following:


•	conditions in the oil and natural gas industry, especially oil and natural gas prices and capital expenditures by oil and natural gas companies;


•	volatility in oil and natural gas prices;


•	our ability to implement price increases or maintain pricing on our core services;


•	risks that we may not be able to reduce, and could even experience increases in, the costs of labor, fuel, equipment and supplies employed in our businesses;


•	industry capacity;


•	asset impairments or other charges;


•	the periodic low demand for our services and resulting operating losses and negative cash flows;


•	our highly competitive industry as well as operating risks, which are primarily self-insured, and the possibility that our insurance may not be adequate to cover all of our losses or liabilities;

Table of Contents


•	significant costs and potential liabilities resulting from compliance with applicable laws, including those resulting from environmental, health and safety laws and regulations, specifically those relating to hydraulic fracturing, as well as climate change legislation or initiatives;


•	our historically high employee turnover rate and our ability to replace or add workers, including executive officers and skilled workers;


•	our ability to incur debt or long-term lease obligations;


•	our ability to implement technological developments and enhancements;


•	severe weather impacts on our business, including from hurricane activity;


•	our ability to successfully identify, make and integrate acquisitions and our ability to finance future growth of our operations or future acquisitions;


•	our ability to achieve the benefits expected from disposition transactions;


•	the loss of one or more of our larger customers;


•	our ability to generate sufficient cash flow to meet debt service obligations;


•	the amount of our debt and the limitations imposed by the covenants in the agreements governing our debt, including our ability to comply with covenants under our debt agreements;


•	an increase in our debt service obligations due to variable rate indebtedness;


•	our inability to achieve our financial, capital expenditure and operational projections, including quarterly and annual projections of revenue and/or operating income and our inaccurate assessment of future activity levels, customer demand, and pricing stability which may not materialize (whether for Key as a whole or for geographic regions and/or business segments individually);


•	our ability to respond to changing or declining market conditions, including our ability to reduce the costs of labor, fuel, equipment and supplies employed and used in our businesses;


•	our ability to maintain sufficient liquidity;


•	adverse impact of litigation; and


•	other factors affecting our business described in Part I “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017, in Part II, “Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the three-month period ended March 31, 2018 and in the other reports we file with the Securities and Exchange Commission.

Table of Contents

PART I — FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

Key Energy Services, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(in thousands, except share amounts)



	June 30, 2018			December 31, 2017
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	52,262		$	73,065
Restricted cash	—			4,000
Accounts receivable, net of allowance for doubtful accounts of $954 and $875, respectively	93,339			69,319
Inventories	19,188			20,942
Other current assets	15,382			19,477
Total current assets	180,171			186,803
Property and equipment	424,393			413,127
Accumulated depreciation	(124,981		)	(85,813		)
Property and equipment, net	299,412			327,314
Intangible assets, net	433			462
Other non-current assets	9,487			14,542
TOTAL ASSETS	$	489,503		$	529,121
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	15,611		$	13,697
Current portion of long-term debt	2,500			2,500
Other current liabilities	85,899			87,579
Total current liabilities	104,010			103,776
Long-term debt	242,091			243,103
Workers’ compensation, vehicular and health insurance liabilities	25,241			25,393
Other non-current liabilities	28,431			28,166
Commitments and contingencies
Equity:
Preferred stock, $0.01 par value; 10,000,000 authorized and one share issued and outstanding	—			—
Common stock, $0.01 par value; 100,000,000 shares authorized, 20,244,545 and 20,217,641 outstanding	202			202
Additional paid-in capital	262,219			259,314
Retained deficit	(172,691		)	(130,833		)
Total equity	89,730			128,683
TOTAL LIABILITIES AND EQUITY	$	489,503		$	529,121

See the accompanying notes which are an integral part of these condensed consolidated financial statements.

Table of Contents

Key Energy Services, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

(unaudited)




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
REVENUES	$	144,405		$	107,780		$	269,721		$	209,232
COSTS AND EXPENSES:
Direct operating expenses	109,747			63,560			207,958			150,866
Depreciation and amortization expense	20,717			20,910			41,073			42,211
General and administrative expenses	22,854			30,334			47,428			61,330
Impairment expense	—			—			—			187
Operating loss	(8,913		)	(7,024		)	(26,738		)	(45,362		)
Interest expense, net of amounts capitalized	8,573			7,872			16,717			15,582
Other income, net	(752		)	(961		)	(1,759		)	(1,201		)
Reorganization items, net	—			101			—			1,441
Loss before income taxes	(16,734		)	(14,036		)	(41,696		)	(61,184		)
Income tax benefit (expense)	(161		)	853			(162		)	1,142
NET LOSS	$	(16,895	)	$	(13,183	)	$	(41,858	)	$	(60,042	)
Loss per share:
Basic and diluted	$	(0.84	)	$	(0.66	)	$	(2.07	)	$	(2.99	)
Weighted average shares outstanding:
Basic and diluted	20,231			20,099			20,224			20,098

See the accompanying notes which are an integral part of these condensed consolidated financial statements.

Table of Contents

Key Energy Services, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

(unaudited)




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
NET LOSS	$	(16,895	)	$	(13,183	)	$	(41,858	)	$	(60,042	)
Other comprehensive income (loss):
Foreign currency translation income (loss)	—			(215		)	—			1,018
COMPREHENSIVE LOSS	$	(16,895	)	$	(13,398	)	$	(41,858	)	$	(59,024	)

See the accompanying notes which are an integral part of these condensed consolidated financial statements.

Table of Contents

Key Energy Services, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(in thousands)

(unaudited)




	Six Months Ended
	June 30,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(41,858	)	$	(60,042	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization expense	41,073			42,211
Impairment expense	—			187
Bad debt expense	427			854
Accretion of asset retirement obligations	80			99
Loss from equity method investments	—			560
Amortization of deferred financing costs	238			239
Deferred income tax benefit	—			(30		)
Income on disposal of assets, net	(5,467		)	(21,599		)
Share-based compensation	2,902			8,159
Changes in working capital:
Accounts receivable	(24,447		)	4,448
Other current assets	5,850			7,297
Accounts payable, accrued interest and accrued expenses	(565		)	(17,966		)
Share-based compensation liability awards	799			—
Other assets and liabilities	5,710			8,395
Net cash used in operating activities	(15,258		)	(27,188		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(17,173		)	(7,236		)
Proceeds from sale of assets	8,875			24,106
Net cash provided by (used in) investing activities	(8,298		)	16,870
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt	(1,250		)	(1,250		)
Payment of deferred financing costs	—			(350		)
Repurchases of common stock	—			(54		)
Proceeds from exercise of warrants	3			—
Net cash used in financing activities	(1,247		)	(1,654		)
Effect of changes in exchange rates on cash	—			144
Net decrease in cash, cash equivalents and restricted cash	(24,803		)	(11,828		)
Cash, cash equivalents, and restricted cash, beginning of period	77,065			115,212
Cash, cash equivalents, and restricted cash, end of period	$	52,262		$	103,384

See the accompanying notes which are an integral part of these condensed consolidated financial statements.

Table of Contents

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS

NOTE 1. GENERAL

Key Energy Services, Inc., and its wholly owned subsidiaries (collectively, “Key,” the “Company,” “we,” “us,” “its,” and “our”) provide a full range of well services to major oil companies and independent oil and natural gas production companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services, and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States. An important component of the Company’s growth strategy is to make acquisitions that will strengthen its core services or presence in selected markets, and the Company also makes strategic divestitures from time to time. The Company expects that the industry in which it operates will experience consolidation, and the Company expects to explore opportunities and engage in discussions regarding these opportunities, which could include mergers, consolidations or acquisitions or further dispositions or other transactions, although there can be no assurance that any such activities will be consummated.

The accompanying unaudited condensed consolidated financial statements were prepared using generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”). The condensed December 31, 2017 balance sheet was prepared from audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Form 10-K”). Certain information relating to our organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted in this Quarterly Report on Form 10-Q. These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2017 Form 10-K.

The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair presentation of our financial position, results of operations and cash flows for the interim periods presented herein. The results of operations for the six months ended June 30, 2018 are not necessarily indicative of the results expected for the full year or any other interim period, due to fluctuations in demand for our services, timing of maintenance and other expenditures, and other factors.

We have evaluated events occurring after the balance sheet date included in this Quarterly Report on Form 10-Q and through the date on which the unaudited condensed consolidated financial statements were issued, for possible disclosure of a subsequent event.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES

The preparation of these unaudited condensed consolidated financial statements requires us to develop estimates and to make assumptions that affect our financial position, results of operations and cash flows. These estimates may also impact the nature and extent of our disclosure, if any, of our contingent liabilities. Among other things, we use estimates to (i) analyze assets for possible impairment, (ii) determine depreciable lives for our assets, (iii) assess future tax exposure and realization of deferred tax assets, (iv) determine amounts to accrue for contingencies, (v) value tangible and intangible assets, (vi) assess workers’ compensation, vehicular liability, self-insured risk accruals and other insurance reserves, (vii) provide allowances for our uncollectible accounts receivable, (viii) value our asset retirement obligations, and (ix) value our equity-based compensation. We review all significant estimates on a recurring basis and record the effect of any necessary adjustments prior to publication of our financial statements. Adjustments made with respect to the use of estimates relate to improved information not previously available. Because of the limitations inherent in this process, our actual results may differ materially from these estimates. We believe that the estimates used in the preparation of these interim financial statements are reasonable.

Revenue Recognition

We recognize revenues to depict the transfer of control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. See “Note 3. Adoption of ASC 606, Revenue from Contracts with Customers” for further discussion on Revenues.

We recognize revenue based on the ASC 606 model, comprising the following five steps: (i) a contract with the customer exists, (ii) performance obligations have been identified, (iii) the price to the customer has been determined, (iv) the price has been allocated to the performance obligations, and (v) the performance obligation is satisfied. We generally determine that these steps have been satisfied as follows:

Table of Contents

A contract with the customer exists when a final understanding between us and our customer has occurred, and can be evidenced by a completed customer purchase order, field ticket, supplier contract, or master service agreement.

Performance obligations have been identified when we have determined the contractual requirements pursuant to the terms of the arrangement. We have a process to determine performance obligations for our contracts.

The price to the customer is determinable and allocated when the amount that is required to be paid is estimated. A price that is determinable is evidenced by contractual terms, our price book, a completed customer purchase order, or a field ticket.

The performance obligation is satisfied in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue as the services are provided, typically daily, as we have the right to invoice the customer for the services performed.

As an accounting policy election, the Company excludes from the measurement of the transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Company from a customer.

There have been no material changes or developments in our evaluation of accounting estimates and underlying assumptions or methodologies that we believe to be a “Critical Accounting Policy or Estimate” as disclosed in our 2017 Form 10-K.

Recent Accounting Developments

ASU 2018-02. In February 2018, the FASB issued ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This standard allows a reclassification from accumulated other comprehensive income (loss) to retained earnings for stranded tax effects resulting from the U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”) that was enacted on December 22, 2017. We adopted this guidance as of January 1, 2018. The adoption of this standard did not have an impact on our consolidated financial statements.

ASU 2016-18. In November 2016, the FASB issued ASU, 2016-18 Statement of Cash Flows (Topic 230), Restricted Cash. This standard provides guidance on the presentation of restricted cash and restricted cash equivalents in the statement of cash flows. Restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statements of cash flows. The amendments of this ASU should be applied using a retrospective transition method and are effective for reporting periods beginning after December 15, 2017, with early adoption permitted. We adopted the new standard effective January 1, 2018 and other than the revised statement of cash flows presentation of restricted cash, the adoption of this standard did not have an impact on our consolidated financial statements.

ASU 2016-15. In August 2016 the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments, that clarifies how entities should classify certain cash receipts and cash payments on the statement of cash flows. The guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. The guidance will be effective for annual periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted. We adopted the new standard effective January 1, 2018 and the adoption of this standard did not have a material impact on our consolidated financial statements.

ASU 2016-13. In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326), Measurement of Credit Losses on Financial Instruments that will change how companies measure credit losses for most financial assets and certain other instruments that aren’t measured at fair value through net income. The standard will replace today’s “incurred loss” approach with an “expected loss” model for instruments measured at amortized cost. For available-for-sale debt securities, entities will be required to record allowances rather than reduce the carrying amount. The amendments in this update will be effective for annual periods beginning after December 15, 2019 and interim periods within those annual periods. Early adoption is permitted for annual periods beginning after December 15, 2018. The Company is evaluating the effect of this standard on our consolidated financial statements.

ASU 2016-02. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which will replace the existing lease guidance. The new standard is intended to provide enhanced transparency and comparability by requiring lessees to record right-of-use assets and corresponding lease liabilities on the balance sheet. Additional disclosure requirements include qualitative disclosures along with specific quantitative disclosures with the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for the Company for annual reporting periods beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. The new standard is required to be applied with a modified retrospective approach to each prior reporting period presented. We are currently evaluating the standard to determine the impact of its adoption on the consolidated financial statements.

ASU 2014-09. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The objective of this ASU is to establish the principles to report useful information to users of financial statements about the nature,

Table of Contents

amount, timing, and uncertainty of revenue from contracts with customers. The core principle is to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 must be adopted using either a full retrospective method or a modified retrospective method. We adopted the new standard effective January 1, 2018 using the full retrospective method and the adoption of this standard did not have a material impact on our consolidated financial statements.

NOTE 3. ADOPTION OF ASC 606, "REVENUE FROM CONTRACTS WITH CUSTOMERS"

On January 1, 2018, we adopted ASC 606 using the full retrospective method applied to those contracts that were not completed as of December 15, 2016. As noted in prior periods, we emerged from voluntary reorganization under Chapter 11 of the United States Bankruptcy Code on December 15, 2016 and therefore applied fresh-start accounting and adopted ASC 606 in effect at the fresh-start accounting date. As a result of electing to use the full retrospective adoption approach as described above, results for reporting periods beginning after December 15, 2016 are presented under ASC 606.

The adoption of ASC 606 did not have a material impact on our consolidated financial statements, and we did not record any adjustments to opening retained earnings as of December 15, 2016, because our services and rental contracts are principally charged on an hourly or daily rate basis and are primarily short-term in nature, typically less than 30 days.

Revenues are recognized when control of the promised goods or services is transferred to our customers, in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. The following table presents our revenues disaggregated by revenue source (in thousands). Sales taxes are excluded from revenues.



	Six Months Ended
	June 30,
	2018		2017
Rig Services	$	150,760	$	122,093
Fluid Management Services	46,344		36,762
Coiled Tubing Services	42,293		14,506
Fishing and Rental Services	30,324		31,631
International	—		4,240
Total	$	269,721	$	209,232

Disaggregation of Revenue

We have disaggregated our revenues by our reportable segments including Rig Services, Fluid Management Services, Coiled Tubing Services and Fishing & Rental Services.

Rig Services

We recognize revenue within the Rig Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue as the services are provided, typically daily, as we have the right to invoice the customer for the services performed. Rig Services are billed and paid monthly. Payment terms for Rig Services are usually 30 days from invoice receipt.

Fluid Management Services

We recognize revenue within the Fluid Management Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue as the services are provided, typically

Table of Contents

daily, as we have the right to invoice the customer for the services performed. Fluid Management Services are billed and paid monthly. Payment terms for Fluid Management Services are usually 30 days from invoice receipt.

Coiled Tubing Services

Coiled Tubing Services involve the use of a continuous metal pipe spooled onto a large reel, which is then deployed into oil and natural gas wells to perform various applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, and formation stimulations utilizing acid and chemical treatments. Coiled tubing is also used for a number of horizontal well applications such as milling temporary isolation plugs that separate frac zones, and various other pre- and post-hydraulic fracturing well preparation services.

We recognize revenue within the Coiled Tubing Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue, typically daily, as the services are provided as we have the right to invoice the customer for the services performed. Coiled Tubing Services are billed and paid monthly. Payment terms for Coiled Tubing Services are usually 30 days from invoice receipt.

Fishing and Rental Services

We offer a full line of services and rental equipment designed for use in providing drilling and workover services. Fishing services involve recovering lost or stuck equipment in the wellbore utilizing a broad array of “fishing tools.” Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk® pipe-handling units and services), pressure-control equipment, pumps, power swivels, reversing units, foam air units.

We recognize revenue within the Fishing and Rental Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue as the services are provided, typically daily, as we have the right to invoice the customer for the services performed. Fishing and Rental Services are billed and paid monthly. Payment terms for Fishing and Rental Services are usually 30 days from invoice receipt.

International

Our former International segment included our former operations in Canada and Russia. Our services in Russia consisted of rig-based services such as the maintenance, workover, and recompletion of existing oil wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. We also had a technology development and control systems business based in Canada, which was focused on the development of hardware and software related to oilfield service equipment controls, data acquisition and digital information flow.

We recognized revenue within the International segment by measuring progress toward satisfying the performance obligation in a manner that best depicted the transfer of goods or services to the customer. The control over services was transferred as the services were rendered to the customer. Specifically, we recognized revenue as the services were provided, typically daily, as we had the right to invoice the customer for the services performed. Services within the international segment were billed and paid monthly. Payment terms for services within the International segment were usually 30 days from invoice receipt.

Arrangements with Multiple Performance Obligations

Our contracts with customers may include multiple performance obligations. For such arrangements, we allocate revenues to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers or using expected cost-plus margin. For combined products and services within a contract, we account for individual products and services separately if they are distinct- i.e. if a product or service is separately identifiable from other items in the contract and if a customer can benefit from it on its own or with other resources that are readily available to the customer. The consideration (including any discounts) is allocated between separate products and services within a contract based on the prices at which we separately sell our services. For items that are not sold separately, we estimate the standalone selling prices using the expected cost-plus margin approach.

Contract Balances

Under our revenue contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our revenue contracts do not give rise to contract assets or liabilities under ASC 606.

Practical Expedients and Exemptions

We generally expense sales commissions when incurred because the amortization period would have been one year or less. These costs are recorded within general and administrative expenses.

Table of Contents

The majority of our services are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Additionally, our payment terms are short-term in nature with settlements of one year or less. We have, therefore, utilized the practical expedient in ASC 606-10-32-18 exempting the Company from adjusting the promised amount of consideration for the effects of a significant financing component given that the period between when the entity transfers a promised good or service to a customer and when the customer pays for that good or service will be one year or less.

Further, in many of our service contracts we have a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date (for example, a service contract in which an entity bills a fixed amount for each hour of service provided). For those contracts, we have utilized the practical expedient in ASC 606-10-55-18 exempting the Company from disclosure of the entity to recognize revenue in the amount to which the Company has a right to invoice.

Accordingly, we do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

NOTE 4. EQUITY

A reconciliation of the total carrying amount of our equity accounts for the six months ended June 30, 2018 is as follows (in thousands):



	COMMON STOCKHOLDERS
	Common Stock			Additional Paid-in Capital		Retained Deficit			Total
	Number of Shares	Amount at Par		Additional Paid-in Capital		Retained Deficit			Total
Balance at December 31, 2017	20,217	$	202	$	259,314	$	(130,833	)	$	128,683
Exercise of warrants	—	—		3		—			3
Share-based compensation	28	—		2,902		—			2,902
Net loss	—	—		—		(41,858		)	(41,858		)
Balance at June 30, 2018	20,245	$	202	$	262,219	$	(172,691	)	$	89,730

NOTE 5. OTHER BALANCE SHEET INFORMATION

The table below presents comparative detailed information about other current assets at June 30, 2018 and December 31, 2017 (in thousands):




	June 30, 2018		December 31, 2017
Other current assets:
Prepaid current assets	$	6,897	$	9,598
Reinsurance receivable	7,263		7,328
Other	1,222		2,551
Total	$	15,382	$	19,477

The table below presents comparative detailed information about other non-current assets at June 30, 2018 and December 31, 2017 (in thousands):




	June 30, 2018		December 31, 2017
Other non-current assets:
Reinsurance receivable	$	7,662	$	7,768
Deposits	1,223		1,246
Other	602		5,528
Total	$	9,487	$	14,542

Table of Contents

The table below presents comparative detailed information about other current liabilities at June 30, 2018 and December 31, 2017 (in thousands):




	June 30, 2018		December 31, 2017
Other current liabilities:
Accrued payroll, taxes and employee benefits	$	20,472	$	19,874
Accrued operating expenditures	15,168		11,644
Income, sales, use and other taxes	9,694		12,151
Self-insurance reserve	27,355		26,761
Accrued interest	7,003		6,605
Accrued insurance premiums	1,593		4,077
Unsettled legal claims	3,470		4,747
Accrued severance	250		250
Other	894		1,470
Total	$	85,899	$	87,579

The table below presents comparative detailed information about other non-current liabilities at June 30, 2018 and December 31, 2017 (in thousands):




	June 30, 2018		December 31, 2017
Other non-current liabilities:
Asset retirement obligations	$	9,005	$	8,931
Environmental liabilities	1,889		1,977
Accrued sales, use and other taxes	17,143		17,142
Other	394		116
Total	$	28,431	$	28,166

NOTE 6. INTANGIBLE ASSETS

The components of our other intangible assets as of June 30, 2018 and December 31, 2017 are as follows (in thousands):




	June 30, 2018			December 31, 2017
Trademark:
Gross carrying value	$	520		$	520
Accumulated amortization	(87		)	(58		)
Net carrying value	$	433		$	462

The weighted average remaining amortization periods and expected amortization expense for the next five years for our definite lived intangible assets are as follows:



	Weighted average remaining amortization period (years)	Expected amortization expense (in thousands)
	Weighted average remaining amortization period (years)	Remainder of 2018		2019		2020		2021		2022		2023
Trademarks	7.5	$	29	$	58	$	58	$	58	$	58	$	58

Amortization expense for our intangible assets was less than $0.1 million for the three and six months ended June 30, 2018 and 2017.

Table of Contents

NOTE 7. DEBT

As of June 30, 2018 and December 31, 2017, the components of our debt were as follows (in thousands):




	June 30, 2018			December 31, 2017
Term Loan Facility due 2021	$	246,250		$	247,500
Unamortized debt issuance costs	(1,659		)	(1,897		)
Total	244,591			245,603
Less current portion	(2,500		)	(2,500		)
Long-term debt	$	242,091		$	243,103

ABL Facility

On December 15, 2016, the Company and Key Energy Services, LLC, as borrowers (the “ABL Borrowers”), entered into the ABL Facility with the financial institutions party thereto from time to time as lenders (the “ABL Lenders”), Bank of America, N.A., as administrative agent for the lenders (the “Administrative Agent”) and Bank of America, N.A. and Wells Fargo Bank, National Association, as co-collateral agents for the lenders. The ABL Facility provides for aggregate initial commitments from the ABL Lenders of $80 million, which, on February 3, 2017 was increased to $100 million, and matures on June 15, 2021.

The ABL Facility provides the ABL Borrowers with the ability to borrow up to an aggregate principal amount equal to the lesser of (i) the aggregate revolving commitments then in effect and (ii) the sum of 85% of the value of eligible accounts receivable plus (b) 80% of the value of eligible unbilled accounts receivable, subject to a limit equal to the greater of (x) $35 million and (y) 25% of the commitments. The amount that may be borrowed under the ABL Facility is subject to increase or reduction based on certain segregated cash or reserves provided for by the ABL Facility. In addition, the percentages of accounts receivable and unbilled accounts receivable included in the calculation described above is subject to reduction to the extent of certain bad debt write-downs and other dilutive items provided in the ABL Facility.

Borrowings under the ABL Facility will bear interest, at the ABL Borrowers’ option, at a per annum rate equal to (i) LIBOR for 30, 60, 90, 180, or, with the consent of the ABL Lenders, 360 days, plus an applicable margin that varies from 2.5% to 4.5% depending on the Borrowers’ fixed charge coverage ratio at such time or (ii) a base rate equal to the sum of (a) the greatest of (x) the prime rate, (y) the federal funds rate, plus 0.50% or (z) 30-day LIBOR, plus 1.0% plus (b) an applicable margin that varies from 1.50% to 3.50% depending on the Borrowers’ fixed charge coverage ratio at such time. In addition, the ABL Facility provides for unused line fees of 1.00% to 1.25% per year, depending on utilization, letter of credit fees and certain other factors.

The ABL Facility may in the future be guaranteed by certain of the Company’s existing and future subsidiaries (the “ABL Guarantors,” and together with the ABL Borrowers, the “ABL Loan Parties”). To secure their obligations under the ABL Facility, each of the ABL Loan Parties has granted or will grant, as applicable, to the Administrative Agent a first-priority security interest for the benefit of the ABL Lenders in its present and future accounts receivable, inventory and related assets and proceeds of the foregoing (the “ABL Priority Collateral”). In addition, the obligations of the ABL Loan Parties under the ABL Facility are secured by second-priority liens on the Term Priority Collateral (as described below under “Term Loan Facility”).

The revolving loans under the ABL Facility may be voluntarily prepaid, in whole or in part, without premium or penalty, subject to breakage or similar costs.

The ABL Facility contains certain affirmative and negative covenants, including covenants that restrict the ability of the ABL Loan Parties to take certain actions including, among other things and subject to certain significant exceptions, the incurrence of debt, the granting of liens, the making of investments, entering into transactions with affiliates, the payment of dividends and the sale of assets. The ABL Facility also contains a requirement that the ABL Borrowers comply, during certain periods, with a fixed charge coverage ratio of 1.00 to 1.00.

As of June 30, 2018, we have no borrowings outstanding and $35.6 million of letters of credit outstanding with borrowing capacity of $38.3 million available subject to covenant constraints under our ABL Facility.

Term Loan Facility

On December 15, 2016, the Company entered into the Term Loan Facility among the Company, as borrower, certain subsidiaries of the Company named as guarantors therein, the financial institutions party thereto from time to time as Lenders (collectively, the “Term Loan Lenders”) and Cortland Capital Market Services LLC and Cortland Products Corp., as agent for the Lenders. The Term Loan Facility had an initial outstanding principal amount of $250 million.

Table of Contents

The Term Loan Facility will mature on December 15, 2021, although such maturity date may, at the Company’s request, be extended by one or more of the Term Loan Lenders pursuant to the terms of the Term Loan Facility. Borrowings under the Term Loan Facility will bear interest, at the Company’s option, at a per annum rate equal to (i) LIBOR for one, two, three, six, or, with the consent of the Term Loan Lenders, 12 months, plus 10.25% or (ii) a base rate equal to the sum of (a) the greatest of (x) the prime rate, (y) the Federal Funds rate, plus 0.50% and (z) 30-day LIBOR, plus 1.0% plus (b) 9.25%.

The Term Loan Facility is guaranteed by certain of the Company’s existing and future subsidiaries (the “Term Loan Guarantors,” and together with the Company, the “Term Loan Parties”). To secure their obligations under the Term Loan Facility, each of the Term Loan Parties has granted or will grant, as applicable, to the agent a first-priority security interest for the benefit of the Term Loan Lenders in substantially all of each Term Loan Party’s assets other than certain excluded assets and the ABL Priority Collateral (the “Term Priority Collateral”). In addition, the obligations of the Term Loan Parties under the Term Loan Facility are secured by second-priority liens on the ABL Priority Collateral (as described above under “ABL Facility”).

The loans under the Term Loan Facility may be prepaid at the Company’s option, subject to the payment of a prepayment premium in certain circumstances as provided in the Term Loan Facility. If a prepayment is made prior to the first anniversary of the loan, such prepayment must be made with make-whole amount with the calculation of the make-whole amount as specified in the Term Loan Facility. If a prepayment is made after the first anniversary of the loan but prior to the second anniversary, such prepayment must be made at 106% of the principle amount, if a prepayment is made after the second anniversary but prior to the third anniversary, such prepayment must be made at 103% of the principle amount. After the third anniversary, if a prepayment is made, no prepayment premium is due. The Company is required to make principal payments in the amount of $625,000 per quarter. In addition, pursuant to the Term Loan Facility, the Company must prepay or offer to prepay, as applicable, term loans with the net cash proceeds of certain debt incurrences and asset sales, excess cash flow, and upon certain change of control transactions, subject in each case to certain exceptions.

The Term Loan Facility contains certain affirmative and negative covenants, including covenants that restrict the ability of the Term Loan Parties to take certain actions including, among other things and subject to certain significant exceptions, the incurrence of debt, the granting of liens, the making of investments, entering into transactions with affiliates, the payment of dividends and the sale of assets. The Term Loan Facility also contains financial covenants requiring that the Company maintain an asset coverage ratio of at least 1.35 to 1.0 and that Liquidity (as defined in the Term Loan Facility) must not be less than $37.5 million (of which at least $20.0 million must be in cash or cash equivalents held in deposit accounts) as of the last day of any fiscal quarter, subject to certain exceptions and cure rights.

The weighted average interest rates on the outstanding borrowings under the Term Loan Facility for the three and six month periods ended June 30, 2018 were as follows:



	Three Months Ended		Six Months Ended
	June 30, 2018		June 30, 2018
Term Loan Facility	12.49	%	12.21	%

NOTE 8. OTHER INCOME

The table below presents comparative detailed information about our other income and expense, shown on the condensed consolidated statements of operations as “other income, net” for the periods indicated (in thousands):




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Interest income	$	(194	)	$	(155	)	$	(378	)	$	(352	)
Other	(558		)	(806		)	(1,381		)	(849		)
Total	$	(752	)	$	(961	)	$	(1,759	)	$	(1,201	)

NOTE 9. INCOME TAXES

The 2017 Tax Act was enacted on December 22, 2017. It is comprehensive tax reform legislation that contains significant changes to corporate taxation. Provisions on the enacted law include a permanent reduction of the corporate income tax rate from 35% to 21%, imposing a mandatory one-time tax on un-repatriated accumulated earnings of foreign subsidiaries, a partial limitation on the deductibility of business interest expense, a limitation on net operating losses to 80% of taxable income each year, a shift of the U.S. taxation of multinational corporations from a tax on worldwide income to a partial territorial system (along with rules that create a new U.S. minimum tax on earnings of foreign subsidiaries), and other related provisions to maintain the U.S. tax base.

Table of Contents

We recognized the income tax effects of the 2017 Tax Act in accordance with Staff Accounting Bulletin No. 118, which provides SEC staff guidance for the application of ASC Topic 740, Income Taxes. The guidance allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. We believe the provisional amounts recorded during the fourth quarter of 2017 continue to represent a reasonable estimate of the accounting implications of the 2017 Tax Act. We did not identify any items for which the income tax effects of the 2017 Tax Act could not be reasonably estimated as of June 30, 2018. However, tax laws and regulations are subject to interpretation and the outcomes of tax disputes are inherently uncertain, and therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.

We are subject to U.S. federal income tax as well as income taxes in multiple state and foreign jurisdictions. Our effective tax rates for the three months ended June 30, 2018 and 2017 were (1.0%) and 6.1%, respectively, and (0.4%) and 1.9% for the six months ended June 30, 2018 and 2017, respectively. The variance between our effective rate and the U.S. statutory rate is due to the mix of pre-tax profit between the U.S. and international taxing jurisdictions with varying statutory rates, the impact of permanent differences, and other tax adjustments, such as valuation allowances against deferred tax assets, and tax expense or benefit recognized for uncertain tax positions.

We continued recording income taxes using a year-to-date effective tax rate method for the three and six months ended June 30, 2018 and 2017. The use of this method was based on our expectations that a small change in our estimated ordinary income could result in a large change in the estimated annual effective tax rate. We will re-evaluate our use of this method each quarter until such time as a return to the annualized effective tax rate method is deemed appropriate.

The Company assesses the realizability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. Due to the history of losses in recent years and the continued challenges affecting the oil and gas industry, management continues to believe it is more likely than not that we will not be able to realize our net deferred tax assets. No release of our deferred tax asset valuation allowance was made during the three or six months ended June 30, 2018.

As of June 30, 2018, we had $0.1 million of unrecognized tax benefits, net of federal tax benefit, which, if recognized, would impact our effective tax rate. We record interest and penalties related to unrecognized tax benefits as income tax expense. We have accrued a liability of less than $0.1 million for the payment of interest and penalties as of June 30, 2018. We believe that it is reasonably possible that all remaining unrecognized tax positions may be recognized in the next twelve months as a result of a lapse of statute of limitations and settlement of ongoing audits.

NOTE 10. COMMITMENTS AND CONTINGENCIES

Litigation

Various suits and claims arising in the ordinary course of business are pending against us. We conduct business throughout the continental United States and may be subject to jury verdicts or arbitrations that result in outcomes in favor of the plaintiffs. We are also exposed to various claims abroad. We continually assess our contingent liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and our need for the disclosure of these items, if any. We establish a provision for a contingent liability when it is probable that a liability has been incurred and the amount is reasonably estimable. We have $3.5 million of other liabilities related to litigation that is deemed probable and reasonably estimable as of June 30, 2018. We do not believe that the disposition of any of these matters will result in an additional loss materially in excess of amounts that have been recorded.

Self-Insurance Reserves

We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred. We estimate general liability claims on a case-by-case basis. We maintain insurance policies for workers’ compensation, vehicle liability and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’ compensation, vehicular liability and general liability claims. The deductibles have a $5 million maximum per vehicular liability claim, $2 million maximum per general liability claim and a $1 million maximum per workers’ compensation claim. As of June 30, 2018 and December 31, 2017, we have recorded $52.6 million and $52.2 million, respectively, of self-insurance reserves related to workers’ compensation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had $14.9 million and $15.1 million of insurance receivables as of June 30, 2018 and December 31, 2017, respectively. We believe that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued for existing claims.

Table of Contents

Environmental Remediation Liabilities

For environmental reserve matters, including remediation efforts for current locations and those relating to previously disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated. As of June 30, 2018 and December 31, 2017, we have recorded $1.9 million and $2.0 million, respectively, for our environmental remediation liabilities. We believe that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued.

NOTE 11. LOSS PER SHARE

Basic loss per share is determined by dividing net loss attributable to Key by the weighted average number of common shares actually outstanding during the period. Diluted loss per common share is based on the increased number of shares that would be outstanding assuming conversion of potentially dilutive outstanding securities using the treasury stock and “as if converted” methods.

The components of our loss per share are as follows (in thousands, except per share amounts):




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Basic and Diluted EPS Calculation:
Numerator
Net loss	$	(16,895	)	$	(13,183	)	$	(41,858	)	$	(60,042	)
Denominator
Weighted average shares outstanding	20,231			20,099			20,224			20,098
Basic and diluted loss per share	$	(0.84	)	$	(0.66	)	$	(2.07	)	$	(2.99	)

Restricted stock units (“RSUs”), stock options, and warrants are included in the computation of diluted earnings per share using the treasury stock method. Restricted stock awards are legally considered issued and outstanding when granted and are included in basic weighted average shares outstanding.

The company has issued potentially dilutive instruments such as RSUs, stock options, and warrants. However, the company did not include these instruments in its calculation of diluted loss per share during the periods presented, because to include them would be anti-dilutive. The following table shows potentially dilutive instruments (in thousands):




	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2018	2017	2018	2017
RSUs	1,115	667	1,121	667
Stock options	163	667	163	667
Warrants	1,838	1,838	1,838	1,838
Total	3,116	3,172	3,122	3,172

No events occurred after June 30, 2018 that would materially affect the number of weighted average shares outstanding.

NOTE 12. SHARE-BASED COMPENSATION

Common Stock Awards

We recognized employee share-based compensation expense of $0.3 million and $3.0 million during the three months ended June 30, 2018 and 2017, respectively. We recognized employee share-based compensation expense of $2.4 million and $5.7 million during the six months ended June 30, 2018 and 2017, respectively. Our employee share-based awards, including common stock awards, stock option awards and phantom shares, vest in equal installments over a three-year period. Additionally, we recognized share-based compensation expense related to our outside directors of $0.2 million during the three months ended June 30, 2018 and 2017. We recognized share-based compensation expense related to our outside directors of $0.5 million during the six months ended June 30, 2018 and 2017. The unrecognized compensation cost related to our unvested share-based awards as of June 30, 2018 is estimated to be $5.7 million and is expected to be recognized over a weighted-average period of 1.5 years.

Table of Contents

Stock Option Awards

We recognized compensation expense related to our stock options of zero and $1.0 million during the three months ended June 30, 2018 and 2017, respectively. We recognized compensation expense related to our stock options of zero and $1.8 million during the six months ended June 30, 2018 and 2017, respectively. As of June 30, 2018, all outstanding stock options are vested and there are no unrecognized costs related to our stock options.

Phantom Share Plan

We recognized compensation expense related to our phantom shares of $0.5 million and zero during the three months ended June 30, 2018 and 2017, respectively. We recognized compensation expense related to our phantom shares of $0.8 million and zero during the six months ended June 30, 2018 and 2017, respectively. The unrecognized compensation cost related to our unvested phantom shares as of June 30, 2018 is estimated to be $1.9 million and is expected to be recognized over a weighted-average period of 1.5 years.

NOTE 13. TRANSACTIONS WITH RELATED PARTIES

The Company has purchased equipment and services from a few affiliates of certain directors. The dollar amounts related to these related party activities are not material to the Company’s condensed consolidated financial statements.

NOTE 14. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

Cash, cash equivalents, accounts receivable, accounts payable and accrued liabilities. These carrying amounts approximate fair value because of the short maturity of the instruments or because the carrying value is equal to the fair value of those instruments on the balance sheet date.

Term Loan Facility due 2021. Because the variable interest rates of these loans approximate current market rates, the fair values of the loans borrowed under this facility approximate their carrying values.

NOTE 15. SEGMENT INFORMATION

Our reportable business segments are Rig Services, Fluid Management Services, Coiled Tubing Services, Fishing and Rental Services and International. We also have a “Functional Support” segment associated with overhead and other costs in support of our reportable segments. Our Rig Services, Fluid Management Services, Coiled Tubing Services, Fishing and Rental Services operate geographically within the United States. The International reportable segment includes our former operations in Canada and Russia. We completed the sale of our Canadian subsidiary and Russian subsidiary in the second and third quarters of 2017, respectively. We evaluate the performance of our segments based on gross margin measures. All inter-segment sales pricing is based on current market conditions.

Rig Services

Our Rig Services include the completion of newly drilled wells, workover and recompletion of existing oil and natural gas wells, well maintenance, and the plugging and abandonment of wells at the end of their useful lives. We also provide specialty drilling services to oil and natural gas producers with certain of our larger rigs that are capable of providing conventional and horizontal drilling services. Our rigs encompass various sizes and capabilities, allowing us to service all types of wells. Many of our rigs are outfitted with our proprietary KeyView® technology, which captures and reports well site operating data and provides safety control systems. We believe that this technology allows our customers and our crews to better monitor well site operations, improves efficiency and safety, and adds value to the services that we offer.

The completion and recompletion services provided by our rigs prepare wells for production, whether newly drilled, or recently extended through a workover operation. The completion process may involve selectively perforating the well casing to access production zones, stimulating and testing these zones, and installing tubular and downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. Completion services vary by well and our work may take a few days to several weeks to perform, depending on the nature of the completion.

The workover services that we provide are designed to enhance the production of existing wells and generally are more complex and time consuming than normal maintenance services. Workover services can include deepening or extending wellbores into new formations by drilling horizontal or lateral wellbores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover.

Maintenance services provided with our rig fleet are generally required throughout the life cycle of an oil or natural gas well. Examples of these maintenance services include routine mechanical repairs to the pumps, tubing and other equipment, removing

Table of Contents

debris and formation material from wellbores, and pulling rods and other downhole equipment from wellbores to identify and resolve production problems. Maintenance services are generally less complicated than completion and workover related services and require less time to perform.

Our rig fleet is also used in the process of permanently shutting-in oil or natural gas wells that are at the end of their productive lives. These plugging and abandonment services generally require auxiliary equipment in addition to a well servicing rig. The demand for plugging and abandonment services is not significantly impacted by the demand for oil and natural gas because well operators are required by state regulations to plug wells that are no longer productive.

Fluid Management Services

We provide transportation and well-site storage services for various fluids utilized in connection with drilling, completions, workover and maintenance activities. We also provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in saltwater disposal wells owned by us or a third party. In addition, we operate a fleet of hot oilers capable of pumping heated fluids used to clear soluble restrictions in a wellbore. Demand and pricing for these services generally correspond to demand for our well service rigs.

Coiled Tubing Services

Coiled Tubing Services involve the use of a continuous metal pipe spooled onto a large reel which is then deployed into oil and natural gas wells to perform various applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, and formation stimulations utilizing acid and chemical treatments. Coiled tubing is also used for a number of horizontal well applications such as milling temporary isolation plugs that separate frac zones, and various other pre- and post-hydraulic fracturing well preparation services.

Fishing and Rental Services

We offer a full line of fishing services and rental equipment designed for use in providing drilling and workover services. Fishing services involve recovering lost or stuck equipment in the wellbore utilizing a broad array of “fishing tools.” Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk^® pipe-handling units and services), pressure-control equipment, pumps, power swivels, reversing units and foam air units. We sold our well testing assets and our frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids in the second quarter of 2017.

Demand for our fishing and rental services is closely related to capital spending by oil and natural gas producers, which is generally a function of oil and natural gas prices.

International

Our former International segment included our former operations in Russia and Canada. In April 2015, we announced our decision to exit markets in which we participate outside of North America. To this end we completed the sale of our Canadian subsidiary and Russian subsidiary in the second and third quarters of 2017, respectively. Our services in Russia consisted of rig-based services such as the maintenance, workover, and recompletion of existing oil wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. Our services in Canada consisted of technology development and control systems, which was focused on the development of hardware and software related to oilfield service equipment controls, data acquisition and digital information flow.

Functional Support

Our Functional Support segment includes unallocated overhead costs associated with administrative support for our U.S. and International reporting segments.

Table of Contents

Financial Summary

The following tables set forth our unaudited segment information as of and for the three and six months ended June 30, 2018 and 2017 (in thousands):



As of and for the three months ended June 30, 2018
	Rig Services		Fluid Management Services			Coiled Tubing Services		Fishing and Rental Services			Functional Support(2)			Reconciling Eliminations			Total
Revenues from external customers	$	80,456	$	23,590		$	23,870	$	16,489		$	—		$	—		$	144,405
Intersegment revenues	191		346			10		556			—			(1,103		)	—
Depreciation and amortization	7,870		5,140			1,312		5,891			504			—			20,717
Other operating expenses	64,532		20,056			19,405		12,739			15,869			—			132,601
Operating income (loss)	8,054		(1,606		)	3,153		(2,141		)	(16,373		)	—			(8,913		)
Interest expense, net of amounts capitalized	—		—			—		—			8,573			—			8,573
Income (loss) before income taxes	8,090		(1,577		)	3,156		(2,135		)	(24,268		)	—			(16,734		)
Long-lived assets(1)	150,617		65,935			19,114		53,170			86,921			(66,425		)	309,332
Total assets	212,059		82,620			37,649		68,716			146,398			(57,939		)	489,503
Capital expenditures	4,282		653			841		414			1,539			—			7,729



As of and for the three months ended June 30, 2017
	Rig Services			Fluid Management Services			Coiled Tubing Services		Fishing and Rental Services			International			Functional Support(2)			Reconciling Eliminations			Total
Revenues from external customers	$	61,802		$	18,867		$	9,165	$	15,776		$	2,170		$	—		$	—		$	107,780
Intersegment revenues	54			354			—		706			—			—			(1,114		)	—
Depreciation and amortization	7,895			5,469			1,284		5,850			32			380			—			20,910
Other operating expenses	54,084			16,625			7,556		(7,568		)	3,490			19,707			—			93,894
Operating income (loss)	(177		)	(3,227		)	325		17,494			(1,352		)	(20,087		)	—			(7,024		)
Reorganization items, net	—			—			—		—			—			101			—			101
Interest expense, net of amounts capitalized	—			—			—		—			—			7,872			—			7,872
Income (loss) before income taxes	(19		)	(3,071		)	330		17,514			(1,044		)	(27,746		)	—			(14,036		)
Long-lived assets(1)	173,679			82,994			21,422		74,285			544			124,711			(99,765		)	377,870
Total assets	297,716			7,617			35,750		367,224			129,176			(46,368		)	(202,762		)	588,353
Capital expenditures	2,642			975			179		503			240			257			—			4,796

Table of Contents



As of and for the six months ended June 30, 2018
	Rig Services		Fluid Management Services			Coiled Tubing Services		Fishing and Rental Services			Functional Support(2)			Reconciling Eliminations			Total
Revenues from external customers	$	150,760	$	46,344		$	42,293	$	30,324		$	—		$	—		$	269,721
Intersegment revenues	256		697			19		1,071			—			(2,043		)	—
Depreciation and amortization	15,657		10,319			2,484		11,645			968			—			41,073
Other operating expenses	124,099		40,695			32,724		24,772			33,096			—			255,386
Operating income (loss)	11,004		(4,670		)	7,085		(6,093		)	(34,064		)	—			(26,738		)
Interest expense, net of amounts capitalized	—		—			—		—			16,717			—			16,717
Income (loss) before income taxes	11,096		(4,605		)	7,088		(6,080		)	(49,195		)	—			(41,696		)
Long-lived assets(1)	150,617		65,935			19,114		53,170			86,921			(66,425		)	309,332
Total assets	212,059		82,620			37,649		68,716			146,398			(57,939		)	489,503
Capital expenditures	7,748		2,136			3,898		780			2,611			—			17,173



As of and for the six months ended June 30, 2017
	Rig Services			Fluid Management Services			Coiled Tubing Services			Fishing and Rental Services		International			Functional Support(2)			Reconciling Eliminations			Total
Revenues from external customers	$	122,093		$	36,762		$	14,506		$	31,631	$	4,240		$	—		$	—		$	209,232
Intersegment revenues	100			638			22			1,626		—			—			(2,386		)	—
Depreciation and amortization	15,219			11,277			2,697			11,800		557			661			—			42,211
Impairment expense	—			—			—			—		187			—			—			187
Other operating expenses	109,138			35,649			13,769			6,214		7,148			40,278			—			212,196
Operating income (loss)	(2,264		)	(10,164		)	(1,960		)	13,617		(3,652		)	(40,939		)	—			(45,362		)
Reorganization items, net	—			—			—			—		—			1,441			—			1,441
Interest expense, net of amounts capitalized	—			—			—			—		—			15,582			—			15,582
Income (loss) before income taxes	(2,110		)	(10,236		)	(1,948		)	13,840		(3,286		)	(57,444		)	—			(61,184		)
Long-lived assets(1)	173,679			82,994			21,422			74,285		544			124,711			(99,765		)	377,870
Total assets	297,716			7,617			35,750			367,224		129,176			(46,368		)	(202,762		)	588,353
Capital expenditures	4,668			1,093			179			530		356			410			—			7,236


(1)	Long-lived assets include fixed assets, intangibles and other non-current assets.


(2)	Functional Support is geographically located in the United States.


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Key Energy Services, Inc., and its wholly owned subsidiaries provide a full range of well services to major oil companies and independent oil and natural gas production companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services, and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most

Table of Contents

major oil and natural gas producing regions of the continental United States. An important component of the Company’s growth strategy is to make acquisitions that will strengthen its core services or presence in selected markets, and the Company also makes strategic divestitures from time to time. To that end, we completed the sale of our Canadian subsidiary and Russian subsidiary in the second and third quarters of 2017, respectively. The Company expects that the industry in which it operates will experience consolidation, and the Company expects to explore opportunities and engage in discussions regarding these opportunities, which could include mergers, consolidations or acquisitions or further dispositions or other transactions, although there can be no assurance that any such activities will be consummated.

The following discussion and analysis should be read in conjunction with the accompanying unaudited condensed consolidated financial statements and related notes as of and for the six months ended June 30, 2018 and 2017, included elsewhere herein, and the audited consolidated financial statements and notes thereto included in our 2017 Form 10-K and Part I, Item 1A. Risk Factors of our 2017 Form 10-K and Part II, Item 1A. Risk Factors of our Quarterly Report on Form 10-Q for the three-month period ended March 31, 2018.

We provide information regarding five business segments: Rig Services, Fluid Management Services, Coiled Tubing Services, Fishing and Rental Services and International. Our former International segment included our former operations in Canada and Russia, which were sold in the second and third quarters of 2017, respectively. We also have a “Functional Support” segment associated with managing our U.S. business segments and previously, our International business segment. See “Note 15. Segment Information” in “Item 1. Financial Statements” of Part I of this report for a summary of our business segments.

PERFORMANCE MEASURES

The Baker Hughes U.S. rig count data, which is publicly available on a weekly basis, is often used as an indicator of overall Exploration and Production (“E&P”) company spending and broader oilfield activity. In assessing overall activity in the U.S. onshore oilfield service industry in which we operate, we believe that the Baker Hughes U.S. land drilling rig count is the best available barometer of E&P companies’ capital spending and resulting activity levels. Historically, our activity levels have been highly correlated with U.S. onshore capital spending by our E&P company customers as a group.



	WTI Cushing Oil(1)		NYMEX Henry Hub Natural Gas(1)		Average Baker Hughes U.S. Land Drilling Rigs(2)	Average AESC Well Service Active Rig Count(3)
2018:
First Quarter	$	62.91	$	3.08	951	1,220
Second Quarter	$	68.07	$	2.85	1,021	1,297

2017:
First Quarter	$	51.60	$	3.02	729	1,128
Second Quarter	$	48.07	$	3.07	878	1,210
Third Quarter	$	48.18	$	2.95	927	1,206
Fourth Quarter	$	55.27	$	2.90	902	1,205


(1)	Represents the average of the monthly average prices for each of the periods presented. Source: EIA and Bloomberg


(2)	Source: www.bakerhughes.com


(3)	Source: www.aesc.net

Internally, we measure activity levels for our well servicing operations primarily through our rig and trucking hours. Generally, as capital spending by E&P companies increases, demand for our services also rises, resulting in increased rig and trucking services and more hours worked. Conversely, when activity levels decline due to lower spending by E&P companies, we generally provide fewer rig and trucking services, which results in fewer hours worked.

Table of Contents

In the U.S., our rig activity occurs primarily on weekdays during daylight hours. Accordingly, we track U.S. rig activity on a “per U.S. working day” basis. Key’s U.S. working days per quarter, which exclude national holidays, are indicated in the table below. Our domestic trucking activity tends to occur on a 24/7 basis, as did our international rig activity prior to the sale of our international operations. Accordingly, we track our international rig activity and our domestic trucking activity on a “per calendar day” basis. The following table presents our quarterly rig and trucking hours from 2017 through the second quarter of 2018:



	Rig Hours			Trucking Hours	Key’s U.S. Working Days(1)
2018:	U.S.	International	Total
First Quarter	175,232	—	175,232	214,194	63
Second Quarter	187,578	—	187,578	201,427	64
Total 2018	362,810	—	362,810	415,621	127

2017:
First Quarter	165,968	2,462	168,430	179,215	64
Second Quarter	163,966	1,701	165,667	185,398	63
Third Quarter	161,725	2,937	164,662	197,319	63
Fourth Quarter	164,480	—	164,480	223,478	61
Total 2017	656,139	7,100	663,239	785,410	251


(1)	Key’s U.S. working days are the number of weekdays during the quarter minus national holidays.

MARKET AND BUSINESS CONDITIONS AND OUTLOOK

Our core businesses depend on our customers’ willingness to make expenditures to produce, develop and explore for oil and natural gas. Industry conditions are influenced by numerous factors, such as oil and natural gas prices, the supply of and demand for oil and natural gas, domestic and worldwide economic conditions, and political instability in oil producing countries and available supply of and demand for the services we provide. Oil and natural gas prices began a rapid and substantial decline in the fourth quarter of 2014. Depressed commodity price conditions persisted and worsened during 2015 and into 2016 and demand for our products and services declined substantially, along with the prices we are able to charge our customers. While we sought to reduce our cost structure to mitigate the negative impact of these declines, we have continued to experience negative operating results and cash flows from operations. In 2017, oil prices recovered off the lows of 2016 and spurred an increase in the Baker Hughes U.S. rig count and related well completion activity, however, the same magnitude of activity increase did not occur in our principal Rig Services business, as measured by the AESC well service rig count, as oil and gas producers’ production maintenance spending has not recovered to the same extent as new well drilling and completion spending.

During the first six months of 2018, we experienced improvement in demand for our services, particularly those driven by the completion of oil and natural gas wells, and were able to increase prices for most of our service offerings. While the oil price has increased to levels not experienced since the end of 2014 and we have seen improvement in demand across all of our service offerings, we have not yet seen a substantial change in activity as it relates to our customer’s spending for the maintenance of existing oil and gas wells, particularly conventional wells, along with the improvement in oil prices. We believe that a continued stabilization of oil prices at a level consistent with current pricing will result in increases in demand for our services. Additionally, we believe that continued aging of horizontal wells and customers choosing to increase production through accretive regular well maintenance in these horizontal wells will strengthen demand for and allow for an increase the price of our services over the next several years. With increased demand for oilfield services broadly and specifically in the services we offer, however, the demand for qualified employees will also increase, which may impact our ability to meet the needs of our customers and constrain growth or offset price increases realized due to inflation in labor costs necessary to attract and retain employees.

Table of Contents

RESULTS OF OPERATIONS

The following table shows our consolidated results of operations for the three and six months ended June 30, 2018 and 2017, respectively (in thousands):




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
REVENUES	$	144,405		$	107,780		$	269,721		$	209,232
COSTS AND EXPENSES:
Direct operating expenses	109,747			63,560			207,958			150,866
Depreciation and amortization expense	20,717			20,910			41,073			42,211
General and administrative expenses	22,854			30,334			47,428			61,330
Impairment expense	—			—			—			187
Operating loss	(8,913		)	(7,024		)	(26,738		)	(45,362		)
Interest expense, net of amounts capitalized	8,573			7,872			16,717			15,582
Other income, net	(752		)	(961		)	(1,759		)	(1,201		)
Reorganization items, net	—			101			—			1,441
Loss before income taxes	(16,734		)	(14,036		)	(41,696		)	(61,184		)
Income tax benefit (expense)	(161		)	853			(162		)	1,142
NET LOSS	$	(16,895	)	$	(13,183	)	$	(41,858	)	$	(60,042	)

Consolidated Results of Operations — Three Months Ended June 30, 2018 and 2017

Revenues

Our revenues for the three months ended June 30, 2018 increased $36.6 million, or 34.0%, to $144.4 million from $107.8 million for the three months ended June 30, 2017, due to an increase in spending from our customers as they react to improving commodity prices. We also benefited in the three months ended June 30, 2018 from sequential improvements in coiled tubing activity as spending for new well construction increased. Internationally, we had no revenue in 2018 as a result of the sale of our operations in Canada and Russia. See “Segment Operating Results — Three Months Ended June 30, 2018 and 2017” below for a more detailed discussion of the change in our revenues.

Direct Operating Expenses

Our direct operating expenses increased $46.2 million, to $109.7 million (76.0% of revenues), for the three months ended June 30, 2018, compared to $63.6 million (59.0% of revenues) for the three months ended June 30, 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense and the decrease in gain on sale of assets related to the sale of our frac stack equipment and well testing services business which was sold in the second quarter of 2017.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $0.2 million, or 0.9%, to $20.7 million during the three months ended June 30, 2018, compared to $20.9 million for the three months ended June 30, 2017. This decrease is primarily due to the sale businesses of our former International segment and our frac stack equipment and well testing services business.

General and Administrative Expenses

General and administrative expenses decreased $7.5 million, to $22.9 million (15.8% of revenues), for the three months ended June 30, 2018, compared to $30.3 million (28.1% of revenues) for the three months ended June 30, 2017. The decrease is primarily due to lower employee compensation costs due to reduced staffing levels.

Interest Expense, Net of Amounts Capitalized

Interest expense increased $0.7 million, or 8.9%, to $8.6 million for the three months ended June 30, 2018, compared to $7.9 million for the same period in 2017. The increase is primarily related to the increase in the variable interest rate on our long-term debt.

Table of Contents

Other Income, Net

During the quarter ended June 30, 2018, we recognized other income, net, of $0.8 million, compared to other income, net, of $1.0 million for the quarter ended June 30, 2017.

The following table summarizes the components of other income, net for the periods indicated:




	Three Months Ended
	June 30,
	2018			2017
Interest income	$	(194	)	$	(155	)
Other	(558		)	(806		)
Total	$	(752	)	$	(961	)

Reorganization Items, Net

There were no reorganization item expenses for the three months ended June 30, 2018, compared to $0.1 million of reorganization item expenses for the same period in 2017. Reorganization items expenses consist of professional fees incurred in connection with our emergence from voluntary reorganization.

Income Tax Benefit (Expense)

We recorded an income tax expense of $0.2 million on a pre-tax loss of $16.7 million in the three months ended June 30, 2018, compared to an income tax benefit of $0.9 million on a pre-tax loss of $14.0 million in the three months ended June 30, 2017. Our effective tax rate was (1.0%) for the three months ended June 30, 2018, compared to 6.1% for the three months ended June 30, 2017. Our effective tax rates differ from the applicable U.S. statutory rates during the three months ended June 30, 2018 (21%) and during the three months ended June 30, 2017 (35%) due to a number of factors, including the mix of profit and loss between domestic and international taxing jurisdictions and the impact of permanent items, including expenses subject to statutorily imposed limitations such as meals and entertainment expenses, that affect book income but do not affect taxable income and discrete tax adjustments, such as valuation allowances against deferred tax assets and tax expense or benefit recognized for uncertain tax positions.

Segment Operating Results — Three Months Ended June 30, 2018 and 2017

The following table shows operating results for each of our segments for the three months ended June 30, 2018 and 2017 (in thousands):



For the three months ended June 30, 2018
	Rig Services		Fluid Management Services			Coiled Tubing Services		Fishing and Rental Services			Functional Support			Total
Revenues from external customers	$	80,456	$	23,590		$	23,870	$	16,489		$	—		$	144,405
Operating expenses	72,402		25,196			20,717		18,630			16,373			153,318
Operating income (loss)	8,054		(1,606		)	3,153		(2,141		)	(16,373		)	(8,913		)



For the three months ended June 30, 2017
	Rig Services			Fluid Management Services			Coiled Tubing Services		Fishing and Rental Services			International			Functional Support			Total
Revenues from external customers	$	61,802		$	18,867		$	9,165	$	15,776		$	2,170		$	—		$	107,780
Operating expenses	61,979			22,094			8,840		(1,718		)	3,522			20,087			114,804
Operating income (loss)	(177		)	(3,227		)	325		17,494			(1,352		)	(20,087		)	(7,024		)

Rig Services

Revenues for our Rig Services segment increased $18.7 million, or 30.2%, to $80.5 million for the three months ended June 30, 2018, compared to $61.8 million for the three months ended June 30, 2017. The increase for this segment is primarily due to an increase in completion and production spending from our customers as they react to improving commodity prices.

Operating expenses for our Rig Services segment were $72.4 million during the three months ended June 30, 2018, which represented an increase of $10.4 million, or 16.8%, compared to $62.0 million for the same period in 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an

Table of Contents

increase in activity levels.

Fluid Management Services

Revenues for our Fluid Management Services segment increased $4.7 million, or 25.0%, to $23.6 million for the three months ended June 30, 2018, compared to $18.9 million for the three months ended June 30, 2017. The increase for this segment is primarily due to an increase in spending from our customers as they react to improving commodity prices.

Operating expenses for our Fluid Management Services segment were $25.2 million during the three months ended June 30, 2018, which represented an increase of $3.1 million, or 14.0%, compared to $22.1 million for the same period in 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an increase in activity levels.

Coiled Tubing Services

Revenues for our Coiled Tubing Services segment increased $14.7 million, or 160.4%, to $23.9 million for the three months ended June 30, 2018, compared to $9.2 million for the three months ended June 30, 2017. The increase for this segment is primarily due to an increase in completion spending from our customers as they react to improving commodity prices.

Operating expenses for our Coiled Tubing Services segment were $20.7 million during the three months ended June 30, 2018, which represented an increase of $11.9 million, or 134.4%, compared to $8.8 million for the same period in 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an increase in activity levels.

Fishing and Rental Services

Revenues for our Fishing and Rental Services segment increased $0.7 million, or 4.5%, to $16.5 million for the three months ended June 30, 2018, compared to $15.8 million for the three months ended June 30, 2017. The increase for this segment is primarily due to an increase in completion and production spending from our customers as they react to improving commodity prices, which is partially offset by the sale of our frac stack equipment and well testing services business, which was sold in the second quarter of 2017.

Operating expenses for our Fishing and Rental Services segment were $18.6 million during the three months ended June 30, 2018, which represented an increase of $20.3 million, compared to a gain of $1.7 million for the same period in 2017. The increase for this segment is primarily due to the decrease in gain on sale of assets related to the sale of our frac stack equipment and well testing services business which was sold in the second quarter of 2017.

International

We sold the remaining businesses of our former International segment, our Canadian subsidiary and our Russian subsidiary, in the second and third quarters of 2017, respectively. Accordingly, for 2018, we no longer have an International segment.

Revenues for our former International segment for the three months ended June 30, 2017 were $2.2 million. Operating expenses for our former International segment for the three months ended June 30, 2017 were $3.5 million. These expenses were related to employee compensation costs and equipment expense and a $0.2 million impairment to reduce the carrying value of the assets and related liabilities of our Russian business unit to fair market value.

Functional Support

Operating expenses for Functional Support, which represent expenses associated with managing our U.S. and former International reporting segments, decreased $3.7 million, or 18.5%, to $16.4 million (11.3% of consolidated revenues) for the three months ended June 30, 2018 compared to $20.1 million (18.6% of consolidated revenues) for the same period in 2017. The decrease is primarily due to lower employee compensation costs due to reduced staffing levels.

Consolidated Results of Operations — Six Months Ended June 30, 2018 and 2017

Revenues

Our revenues for the six months ended June 30, 2018 increased $60.5 million, or 28.9%, to $269.7 million from $209.2 million for the six months ended June 30, 2017, due to an increase in spending from our customers as they react to improving commodity prices. We also benefited in the six months ended June 30, 2018 from sequential improvements in coiled tubing activity as spending for new well construction increased. Internationally, we had no revenue in 2018 as a result of the sale our operations in Canada and Russia. See “Segment Operating Results — Six Months Ended June 30, 2018 and 2017” below for a more detailed discussion of the change in our revenues.

Table of Contents

Direct Operating Expenses

Our direct operating expenses increased $57.1 million, to $208.0 million (77.1% of revenues), for the six months ended June 30, 2018, compared to $150.9 million (72.1% of revenues) for the six months ended June 30, 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an increase in activity levels and, with respect to the increase in repair and maintenance expense due to costs associated with making idle equipment ready for work and the decrease in gain on sale of assets related to the sale of our frac stack equipment and well testing services business which was sold in the second quarter of 2017.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $1.1 million, or 2.7%, to $41.1 million during the six months ended June 30, 2018, compared to $42.2 million for the six months ended June 30, 2017. This decrease is primarily due to the sale businesses of our former International segment and our frac stack equipment and well testing services business.

General and Administrative Expenses

General and administrative expenses decreased $13.9 million, to $47.4 million (17.6% of revenues), for the six months ended June 30, 2018, compared to $61.3 million (29.3% of revenues) for the six months ended June 30, 2017. The decrease is primarily due to lower employee compensation costs due to reduced staffing levels.

Impairment Expense

During the six months ended June 30, 2018, we did not record an impairment. During the six months ended June 30, 2017, we recorded a $0.2 million impairment to reduce the carrying value of the assets and related liabilities of our Russian business unit, which was sold in the third quarter of 2017, to fair market value.

Interest Expense, Net of Amounts Capitalized

Interest expense increased $1.1 million, or 7.3%, to $16.7 million for the six months ended June 30, 2018, compared to $15.6 million for the same period in 2017. The increase is primarily related to the increase in the variable interest rate on our long-term debt.

Other Income, Net

During the six months ended June 30, 2018, we recognized other income, net, of $1.8 million, compared to other income, net, of $1.2 million for the six months ended June 30, 2017.

The following table summarizes the components of other income, net for the periods indicated (in thousands):




	Six Months Ended
	June 30,
	2018			2017
Interest income	$	(378	)	$	(352	)
Other	(1,381		)	(849		)
Total	$	(1,759	)	$	(1,201	)

Reorganization Items, Net

There were no reorganization item expenses for the six months ended, compared to $1.4 million of reorganization item expenses for the same period in 2017. Reorganization items expenses consist of professional fees incurred in connection with our emergence from voluntary reorganization.

Income Tax Benefit (Expense)

We recorded an income tax expense of $0.2 million on a pre-tax loss of $41.7 million for the six months ended June 30, 2018, compared to an income tax benefit of $1.1 million on a pre-tax loss of $61.2 million for the same period in 2017. Our effective tax rate was (0.4%) for the six months ended June 30, 2018, compared to 1.9% for the six months ended June 30, 2017. Our effective tax rates differ from the applicable U.S. statutory rates during the six months ended June 30, 2018, (21%) and during the six months ended June 30, 2017, (35%) due to a number of factors, including the mix of profit and loss between domestic and international taxing jurisdictions and the impact of permanent items, including expenses subject to statutorily imposed limitations such as meals and entertainment expenses, that affect book income but do not affect taxable income and discrete tax adjustments, such as valuation allowances against deferred tax assets and tax expense or benefit recognized for uncertain tax positions.

Table of Contents

Segment Operating Results — Six Months Ended June 30, 2018 and 2017

The following table shows operating results for each of our segments for the six months ended June 30, 2018 and 2017 (in thousands):



For the six months ended June 30, 2018
	Rig Services		Fluid Management Services			Coiled Tubing Services		Fishing and Rental Services			Functional Support			Total
Revenues from external customers	$	150,760	$	46,344		$	42,293	$	30,324		$	—		$	269,721
Operating expenses	139,756		51,014			35,208		36,417			34,064			296,459
Operating income (loss)	11,004		(4,670		)	7,085		(6,093		)	(34,064		)	(26,738		)



For the six months ended June 30, 2017
	Rig Services			Fluid Management Services			Coiled Tubing Services			Fishing and Rental Services		International			Functional Support			Total
Revenues from external customers	$	122,093		$	36,762		$	14,506		$	31,631	$	4,240		$	—		$	209,232
Operating expenses	124,357			46,926			16,466			18,014		7,892			40,939			254,594
Operating income (loss)	(2,264		)	(10,164		)	(1,960		)	13,617		(3,652		)	(40,939		)	(45,362		)

Rig Services

Revenues for our Rig Services segment increased $28.7 million, or 23.5%, to $150.8 million for the six months ended June 30, 2018, compared to $122.1 million for the six months ended June 30, 2017. The increase for this segment is primarily due to an increase in completion and production spending from our customers as they react to improving commodity prices.

Operating expenses for our Rig Services segment were $139.8 million for the six months ended June 30, 2018, which represented an increase of $15.4 million, or 12.4%, compared to $124.4 million for the same period in 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an increase in activity levels.

Fluid Management Services

Revenues for our Fluid Management Services segment increased $9.6 million, or 26.1%, to $46.3 million for the six months ended June 30, 2018, compared to $36.8 million for the six months ended June 30, 2017. The increase for this segment is primarily due an increase in spending from our customers as they react to improving commodity prices.

Operating expenses for our Fluid Management Services segment were $51.0 million for the six months ended June 30, 2018, which represented an increase of $4.1 million, or 8.7%, compared to $46.9 million for the same period in 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an increase in activity levels.

Coiled Tubing Services

Revenues for our Coiled Tubing Services segment increased $27.8 million, or 191.6%, to $42.3 million for the six months ended June 30, 2018, compared to $14.5 million for the six months ended June 30, 2017. The increase for this segment is primarily due an increase in completion spending from our customers as they react to improving commodity prices.

Operating expenses for our Coiled Tubing Services segment were $35.2 million for the six months ended June 30, 2018, which represented an increase of $18.7 million, or 113.8%, compared to $16.5 million for the same period in 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an increase in activity levels.

Fishing and Rental Services

Revenues for our Fishing and Rental Services segment decreased $1.3 million, or 4.1%, to $30.3 million for the six months ended June 30, 2018, compared to $31.6 million for the six months ended June 30, 2017. The decrease for this segment is primarily due to the sale of our frac stack equipment and well testing services business which was sold in the second quarter of 2017, partially offset by an increase in completion and production spending from our customers as they react to improving commodity prices.

Operating expenses for our Fishing and Rental Services segment were $36.4 million for the six months ended June 30, 2018, which represented an increase of $18.4 million, or 102.2%, compared to $18.0 million for the same period in 2017. The

Table of Contents

increase for this segment is primarily due to the decrease in gain on sale of assets related to the sale of our frac stack equipment and well testing services business in the second quarter of 2017.

International

Revenues for our former International segment for the six months ended June 30, 2017 were $4.2 million. Operating expenses for our former International segment for the six months ended June 30, 2017 were $7.9 million. These expenses were related to employee compensation costs and equipment expense and a $0.2 million impairment to reduce the carrying value of the assets and related liabilities of our Russian business unit to fair market value.

Functional Support

Operating expenses for Functional Support, which represent expenses associated with managing our U.S. and International reporting segments, decreased $6.9 million, or 16.8%, to $34.1 million (12.6% of consolidated revenues) for the six months ended June 30, 2018 compared to $40.9 million (19.6% of consolidated revenues) for the same period in 2017. The decrease is primarily due to lower employee compensation costs due to reduced staffing levels.

LIQUIDITY AND CAPITAL RESOURCES

Current Financial Condition and Liquidity

As of June 30, 2018, we had total liquidity of $90.6 million which consists of $52.3 million cash and cash equivalents and $38.3 million of borrowing capacity available under our ABL Facility. This compares to total liquidity of $97.8 million which consists of $73.1 million cash and cash equivalents and $24.7 million of borrowing capacity available under our ABL Facility as of December 31, 2017. Our working capital was $76.2 million as of June 30, 2018, compared to $83.0 million as of December 31, 2017. Our working capital decreased from the prior year end primarily as a result of a decrease in cash, cash equivalents, restricted cash, prepaid assets and inventories, partially offset by an increase in accounts receivable. As of June 30, 2018, we had no borrowings outstanding and $35.6 million in committed letters of credit outstanding under our ABL Facility.

The following table summarizes our cash flows for the six months ended June 30, 2018 and 2017 (in thousands):




	Six Months Ended
	June 30,
	2018			2017
Net cash used in operating activities	$	(15,258	)	$	(27,188	)
Cash paid for capital expenditures	(17,173		)	(7,236		)
Proceeds received from sale of fixed assets	8,875			24,106
Repayments of long-term debt	(1,250		)	(1,250		)
Payment of deferred financing costs	—			(350		)
Other financing activities, net	3			(54		)
Effect of exchange rates on cash	—			144
Net decrease in cash, cash equivalents and restricted cash	$	(24,803	)	$	(11,828	)

Cash used in operating activities was $15.3 million for the six months ended June 30, 2018 compared to cash used in operating activities of $27.2 million for the six months ended June 30, 2017. Cash used in operating activities for the six months ended June 30, 2018 was primarily related to an increase in accounts receivable, partially offset by a decrease in prepaid assets, inventories and other noncurrent assets. Cash used in operating activities for the six months ended June 30, 2017 was primarily related to net loss adjusted for noncash items and a decrease in accrued liabilities, partially offset by a decrease in accounts receivable, prepaid assets, inventories and other noncurrent assets.

Cash used in investing activities was $8.3 million for the six months ended June 30, 2018 compared to cash provided by investing activities of $16.9 million for the six months ended June 30, 2017. Cash outflows during these periods consisted primarily of capital expenditures. Our capital expenditures are primarily related to the addition of new equipment and the ongoing maintenance of our equipment. Cash inflows during these periods consisted primarily of proceeds from sales of fixed assets.

Cash used in financing activities was $1.2 million for the six months ended June 30, 2018 compared to cash used in financing activities of $1.7 million for the six months ended June 30, 2017. Financing cash outflows for the six months ended June 30, 2018 and June 30, 2017 primarily relate to the repayment of long-term debt.

Table of Contents

Sources of Liquidity and Capital Resources

We believe that our internally generated cash flows from operations, current reserves of cash and availability under our ABL Facility are sufficient to finance our cash requirements for current and future operations, budgeted capital expenditures, debt service and other obligations for the next twelve months.

At June 30, 2018, our annual debt maturities for our 2021 Term Loan Facility were as follows (in thousands):




Year	Principal Payments
2018	$	1,250
2019	2,500
2020	2,500
2021	240,000
Total principal payments	$	246,250

ABL Facility

The ABL Facility provides the ABL Borrowers with the ability to borrow up to an aggregate principal amount equal to the lesser of (i) the aggregate revolving commitments then in effect and (ii) the sum of (a) 85% of the value of eligible accounts receivable plus (b) 80% of the value of eligible unbilled accounts receivable, subject to a limit equal to the greater of (x) $35 million and (y) 25% of the commitments. The amount that may be borrowed under the ABL Facility is subject to increase or reduction based on certain segregated cash or reserves provided for by the ABL Facility. In addition, the percentages of accounts receivable and unbilled accounts receivable included in the calculation described above is subject to reduction to the extent of certain bad debt write-downs and other dilutive items provided in the ABL Facility.

Borrowings under the ABL Facility bear interest, at the ABL Borrowers’ option, at a per annum rate equal to (i) LIBOR for 30, 60, 90, 180, or, with the consent of the ABL Lenders, 360 days, plus an applicable margin that varies from 2.50% to 4.50% depending on the Borrowers’ fixed charge coverage ratio at such time or (ii) a base rate equal to the sum of (a) the greatest of (x) the prime rate, (y) the federal funds rate, plus 0.50% or (z) 30-day LIBOR, plus 1.0% plus (b) an applicable margin that varies from 1.50% to 3.50% depending of the Borrowers’ fixed charge coverage ratio at such time. In addition, the ABL Facility provides for unused line fees of 1.00% to 1.25% per year, depending on utilization, letter of credit fees and certain other factors.

The revolving loans under the ABL Facility may be voluntarily prepaid, in whole or in part, without premium or penalty, subject to breakage or similar costs.

The ABL Facility contains certain affirmative and negative covenants, including covenants that restrict the ability of the ABL Loan Parties to take certain actions including, among other things and subject to certain significant exceptions, the incurrence of debt, the granting of liens, the making of investments, entering into transactions with affiliates, the payment of dividends and the sale of assets. The ABL Facility also contains a requirement that the ABL Borrowers comply, during certain periods with a fixed charge coverage ratio of 1.00 to 1.00.

As of June 30, 2018, we have no borrowings outstanding under the ABL Facility and $35.6 million of letters of credit outstanding with borrowing capacity of $38.3 million available subject to covenant constraints under our ABL Facility.

Table of Contents

Term Loan Facility

On December 15, 2016, the Company entered into the Term Loan Facility among the Company, as borrower, certain subsidiaries of the Company named as guarantors therein, the financial institutions party thereto from time to time as Lenders (collectively, the “Term Loan Lenders”) and Cortland Capital Market Services LLC and Cortland Products Corp., as agent for the Lenders. The Term Loan Facility had an outstanding principal amount of $250 million as of December15, 2016.

The Term Loan Facility will mature on December 15, 2021, although such maturity date may, at the Company’s request, be extended by one or more of the Term Loan Lenders pursuant to the terms of the Term Loan Facility. Borrowings under the Term Loan Facility bear interest, at the Company’s option, at a per annum rate equal to (i) LIBOR for one, two, three, six, or, with the consent of the Term Loan Lenders, 12 months, plus 10.25% or (ii) a base rate equal to the sum of (a) the greatest of (x) the prime rate, (y) the Federal Funds rate, plus 0.50% and (z) 30-day LIBOR, plus 1.0% plus (b) 9.25%.

The Term Loan Facility is guaranteed by certain of the Company’s existing and future subsidiaries (the “Term Loan Guarantors,” and together with the Company, the “Term Loan Parties”). To secure their obligations under the Term Loan Facility, each of the Term Loan Parties has granted or will grant, as applicable, to the Agent a first-priority security interest for the benefit of the Term Loan Lenders in substantially all of each Term Loan Party’s assets other than certain excluded assets and the ABL Priority Collateral (the “Term Priority Collateral”). In addition, the obligations of the Term Loan Parties under the Term Loan Facility are secured by second-priority liens on the ABL Priority Collateral (as described above under “ABL Facility”).

Debt Compliance

At June 30, 2018, we were in compliance with all the financial covenants under our ABL Facility and the Term Loan Facility. Based on management’s current projections, we expect to be in compliance with all the covenants under our ABL Facility and Term Loan Facility for the next twelve months. A breach of any of these covenants, ratios or tests could result in a default under our indebtedness.

Capital Expenditures

During the six months ended June 30, 2018, our capital expenditures totaled $17.2 million, primarily related to the addition of new equipment needed to take advantage of the recent increase in activity. Our capital expenditure plan for 2018 contemplates spending between $35 million and $40 million, subject to market conditions. This is primarily related to the addition of new equipment needed to take advantage of the recent increase in activity and the ongoing maintenance of our equipment. Our capital expenditure program for 2018 is subject to market conditions, including activity levels, commodity prices, industry capacity and specific customer needs as well as cash flows, including cash generated from asset sales. Our focus for 2018 will be the maximization of our current equipment fleet, but we may choose to increase our capital expenditures in 2018 to expand our presence in a market. We currently anticipate funding our 2018 capital expenditures through a combination of cash on hand, operating cash flow, proceeds from sales of assets and borrowings under our ABL Facility. Should our operating cash flows or activity levels prove to be insufficient to fund our currently planned capital spending levels, management expects that it will adjust our capital spending plans accordingly. We may also incur capital expenditures for strategic investments and acquisitions.

Table of Contents

Off-Balance Sheet Arrangements

At June 30, 2018 we did not, and we currently do not, have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes in our quantitative and qualitative disclosures about market risk from those disclosed in our 2017 Form 10-K. More detailed information concerning market risk can be found in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2017 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report on Form 10-Q, management performed, with the participation of our Chief Executive Officer and our Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports 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. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on this evaluation, management concluded that our disclosure controls and procedures are effective as of the end of the period covered by this report.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the second quarter of 2018 that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II — OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

We are subject to various suits and claims that have arisen in the ordinary course of business. We do not believe that the disposition of any of our ordinary course litigation will result in a material adverse effect on our consolidated financial position, results of operations or cash flows. For additional information on legal proceedings, see “Note 10. Commitments and Contingencies” in “Item 1. Financial Statements” of Part I of this report, which is incorporated herein by reference.


ITEM 1A.	RISK FACTORS

As of the date of this filing, there have been no material changes in the risk factors previously disclosed in Part I, “Item 1A. Risk Factors” of our 2017 Form 10-K and Part II, “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the three months ended March 31, 2018.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.	OTHER INFORMATION

None.


ITEM 6.	EXHIBITS

The Exhibit Index, which follows the signature pages to this report and is incorporated by reference herein, sets forth a list of exhibits to this report.

EXHIBIT INDEX



Exhibit No.		Description

10.1		Letter Agreement, dated as of May 15, 2018, between the Company and Robert Drummond (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 15, 2018, File No. 001-08038).

10.2		Form of Retention Bonus Award Letter (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 26, 2018, File No. 001-08038).

31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32**		Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101*		Interactive Data File.




*	Filed herewith

**	Furnished herewith

Table of Contents

SIGNATURE

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

August 9, 2018

/s/ J. MARSHALL DODSON

J. Marshall Dodson

Senior Vice President, Chief Financial Officer and Interim Chief Executive Officer
(As duly authorized officer and Principal Financial Officer)