Document

10-Q 1 form10q-q12019.htm 10-Q Document

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 March 31, 2019



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

Commission File Number: 1-8182

PIONEER ENERGY SERVICES CORP.

(Exact name of registrant as specified in its charter)

____________________________________________



TEXAS		74-2088619
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

1250 N.E. Loop 410, Suite 1000 San Antonio, Texas		78209
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code: (855) 884-0575



Securities registered pursuant to Section 12(b) of the Act
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock	PES	New York Stock Exchange

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 x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes x No o

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	o	Accelerated filer	x

Non-accelerated filer	o	Smaller reporting company	o

		Emerging Growth Company	o

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 x

As of April 15, 2019, there were 78,466,260 shares of common stock, par value $0.10 per share, of the registrant outstanding.

PART I. FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31, 2019			December 31, 2018
	(unaudited)			(audited)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	26,855		$	53,566
Restricted cash	998			998
Receivables:
Trade, net of allowance for doubtful accounts	90,816			76,924
Unbilled receivables	27,535			24,822
Insurance recoveries	23,427			23,656
Other receivables	6,307			5,479
Inventory	20,229			18,898
Assets held for sale	4,794			3,582
Prepaid expenses and other current assets	7,307			7,109
Total current assets	208,268			215,034
Property and equipment, at cost	1,125,170			1,118,215
Less accumulated depreciation	607,403			593,357
Net property and equipment	517,767			524,858
Operating lease assets	9,423			—
Other noncurrent assets	1,633			1,658
Total assets	$	737,091		$	741,550

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	38,163		$	34,134
Deferred revenues	1,659			1,722
Accrued expenses:
Payroll and related employee costs	24,699			24,598
Insurance claims and settlements	22,819			23,593
Insurance premiums and deductibles	5,543			5,482
Interest	1,460			6,148
Other	10,233			9,091
Total current liabilities	104,576			104,768
Long-term debt, less unamortized discount and debt issuance costs	465,315			464,552
Noncurrent operating lease liabilities	6,929			—
Deferred income taxes	4,844			3,688
Other noncurrent liabilities	4,460			3,484
Total liabilities	586,124			576,492
Commitments and contingencies (Note 11)
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—			—
Common stock $.10 par value; 200,000,000 shares authorized; 78,456,260 and 78,214,550 shares outstanding at March 31, 2019 and December 31, 2018, respectively	7,933			7,900
Additional paid-in capital	551,382			550,548
Treasury stock, at cost; 874,391 and 789,532 shares at March 31, 2019 and December 31, 2018, respectively	(5,085		)	(4,965		)
Accumulated deficit	(403,263		)	(388,425		)
Total shareholders’ equity	150,967			165,058
Total liabilities and shareholders’ equity	$	737,091		$	741,550

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)



	Three months ended March 31,
	2019			2018
	(in thousands, except per share data)

Revenues	$	146,568		$	144,478

Costs and expenses:
Operating costs	108,585			102,766
Depreciation	22,653			23,747
General and administrative	19,758			19,194
Bad debt expense (recovery), net	62			(52		)
Impairment	1,046			—
Gain on dispositions of property and equipment, net	(1,075		)	(335		)
Total costs and expenses	151,029			145,320
Loss from operations	(4,461		)	(842		)

Other income (expense):
Interest expense, net of interest capitalized	(9,885		)	(9,513		)
Other income, net	684			504
Total other expense, net	(9,201		)	(9,009		)

Loss before income taxes	(13,662		)	(9,851		)
Income tax expense	(1,453		)	(1,288		)
Net loss	$	(15,115	)	$	(11,139	)

Loss per common share - Basic	$	(0.19	)	$	(0.14	)

Loss per common share - Diluted	$	(0.19	)	$	(0.14	)

Weighted average number of shares outstanding—Basic	78,311			77,606

Weighted average number of shares outstanding—Diluted	78,311			77,606

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(unaudited)



	As of and for the three months ended March 31, 2019
	Shares			Amount					Additional Paid In Capital			Accumulated Deficit			Total Shareholders’ Equity
	Common	Treasury		Common		Treasury			Additional Paid In Capital			Accumulated Deficit			Total Shareholders’ Equity
	(in thousands)
Balance as of December 31, 2018	79,005	(790	)	$	7,900	$	(4,965	)	$	550,548		$	(388,425	)	$	165,058
Net loss	—	—		—		—			—			(15,115		)	(15,115		)
Purchase of treasury stock	—	(84	)	—		(120		)	—			—			(120		)
Cumulative-effect adjustment due to adoption of ASC Topic 842	—	—		—		—			—			277			277
Issuance of restricted stock	326	—		33		—			(33		)	—			—
Stock-based compensation expense	—	—		—		—			867			—			867
Balance as of March 31, 2019	79,331	(874	)	$	7,933	$	(5,085	)	$	551,382		$	(403,263	)	$	150,967



	As of and for the three months ended March 31, 2018
	Shares			Amount					Additional Paid In Capital			Accumulated Deficit			Total Shareholders’ Equity
	Common	Treasury		Common		Treasury			Additional Paid In Capital			Accumulated Deficit			Total Shareholders’ Equity
	(in thousands)
Balance as of December 31, 2017	78,350	(631	)	$	7,835	$	(4,416	)	$	546,158		$	(339,481	)	$	210,096
Net loss	—	—		—		—			—			(11,139		)	(11,139		)
Purchase of treasury stock	—	(28	)	—		(96		)	—			—			(96		)
Cumulative-effect adjustment due to adoption of ASC Topic 606	—	—		—		—			—			67			67
Issuance of restricted stock	105	—		10		—			(10		)	—			—
Stock-based compensation expense	—	—		—		—			1,259			—			1,259
Balance as of March 31, 2018	78,455	(659	)	$	7,845	$	(4,512	)	$	547,407		$	(350,553	)	$	200,187

See accompanying notes to consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)



	Three months ended March 31,
	2019			2018
	(in thousands)
Cash flows from operating activities:
Net loss	$	(15,115	)	$	(11,139	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation	22,653			23,747
Allowance for doubtful accounts, net of recoveries	62			(52		)
Gain on dispositions of property and equipment, net	(1,075		)	(335		)
Stock-based compensation expense	867			1,259
Phantom stock compensation expense	848			430
Amortization of debt issuance costs and discount	763			707
Impairment	1,046			—
Deferred income taxes	1,156			911
Change in other noncurrent assets	699			(463		)
Change in other noncurrent liabilities	(20		)	1,414
Changes in current assets and liabilities:
Receivables	(17,488		)	(3,296		)
Inventory	(1,293		)	(2,042		)
Prepaid expenses and other current assets	(178		)	882
Accounts payable	2,339			51
Deferred revenues	(64		)	(108		)
Accrued expenses	(5,990		)	(6,908		)
Net cash provided by (used in) operating activities	(10,790		)	5,058

Cash flows from investing activities:
Purchases of property and equipment	(16,844		)	(11,657		)
Proceeds from sale of property and equipment	1,043			1,283
Proceeds from insurance recoveries	—			523
Net cash used in investing activities	(15,801		)	(9,851		)

Cash flows from financing activities:
Debt issuance costs	—			(33		)
Purchase of treasury stock	(120		)	(96		)
Net cash used in financing activities	(120		)	(129		)

Net decrease in cash, cash equivalents and restricted cash	(26,711		)	(4,922		)
Beginning cash, cash equivalents and restricted cash	54,564			75,648
Ending cash, cash equivalents and restricted cash	$	27,853		$	70,726

Supplementary disclosure:
Interest paid	$	13,887		$	13,515
Income tax paid	$	1,013		$	658
Noncash investing and financing activity:
Change in capital expenditure accruals	$	1,531		$	2,931

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Business

Our drilling services business segments provide contract land drilling services through three domestic divisions which are located in the Marcellus/Utica, Permian Basin and Eagle Ford, and Bakken regions, and internationally in Colombia. We provide a comprehensive service offering which includes the drilling rig, crews, supplies and most of the ancillary equipment needed to operate our drilling rigs. Our drilling rigs are equipped with 1,500 horsepower or greater drawworks, are 100% pad-capable and offer the latest advancements in pad drilling. The following table summarizes our current rig fleet count and composition for each drilling services business segment:



	Multi-well, Pad-capable
	AC rigs	SCR rigs	Total
Domestic drilling	17	—	17
International drilling	—	8	8
			25

Our production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of exploration and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Gulf Coast, Mid-Continent and Rocky Mountain states. As of March 31, 2019, the fleet count for each of our production services business segments are as follows:



	550 HP	600 HP	Total
Well servicing rigs, by horsepower (HP) rating	113	12	125

			Total
Wireline services units			93
Coiled tubing services units			9

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of Pioneer Energy Services Corp. and our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of our management, all adjustments (consisting of normal, recurring accruals) necessary for a fair presentation have been included. We suggest that you read these unaudited condensed consolidated financial statements together with the consolidated financial statements and the related notes included in our annual report on Form 10-K for the year ended December 31, 2018.

Use of Estimates — In preparing the accompanying unaudited condensed consolidated financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our estimates of certain variable revenues and amortization periods of certain deferred revenues and costs associated with drilling daywork contacts, our estimates of projected cash flows and fair values for impairment evaluations, our estimate of the valuation allowance for deferred tax assets, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance and our estimate of compensation related accruals.

Subsequent Events — In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after March 31, 2019, through the filing of this Form 10-Q, for inclusion as necessary.

Reclassifications — Certain amounts in the unaudited condensed consolidated financial statements for the prior year periods have been reclassified to conform to the current year’s presentation.

Change in Accounting Principle and Recently Issued Accounting Standards

Changes to accounting principles generally accepted in the United States of America (“U.S. GAAP”) are established by the Financial Accounting Standards Board (FASB) in the form of Accounting Standards Updates (ASUs) to the FASB Accounting Standards Codification (ASC). We consider the applicability and impact of all ASUs. Any ASUs not listed below were assessed and determined to be either not applicable or are expected to have an immaterial impact on our consolidated financial position and results of operations.

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases, which among other things, requires lessees to recognize substantially all leases on the balance sheet, with expense recognition that is similar to the former lease standard, and aligns the principles of lessor accounting with the principles of the FASB’s new revenue guidance in ASC Topic 606. In July 2018, the FASB issued ASU No. 2018-11, Leases: Targeted Improvements, which provides an option to apply the guidance prospectively, and provides a practical expedient allowing lessors to combine the lease and non-lease components of revenues where the revenue recognition pattern is the same and where the lease component, when accounted for separately, would be considered an operating lease. The practical expedient also allows a lessor to account for the combined lease and non-lease components under ASC Topic 606, Revenue from Contracts with Customers, when the non-lease component is the predominant element of the combined component.

As a lessor, we elected to apply the practical expedient which allows us to continue to recognize our revenues (both lease and service components) under ASC Topic 606, and continue to present them as one revenue stream in our unaudited condensed consolidated statements of operations. As a lessee, this standard primarily impacts our accounting for long-term real estate and office equipment leases, for which we recognized an operating lease asset and a corresponding operating lease liability on our unaudited condensed consolidated balance sheet of $9.8 million at the adoption date of January 1, 2019. For leases that commenced prior to adoption of ASC Topic 842, we elected to apply the package of practical expedients which allows us to carry forward the historical lease classification. The adoption of ASC Topic 842 also resulted in a cumulative effect adjustment of $0.3 million after applicable income taxes, related to the write off of previously unamortized deferred lease liabilities at the date of adoption. For more information about the accounting under ASC Topic 842, and disclosures under the new standard, see Note 3, Leases.

Additional Detail of Account Balances

Cash Equivalents and Restricted Cash — Cash equivalents at March 31, 2019 and December 31, 2018 were $17.7 million and $40.6 million, respectively, consisting of investments in highly-liquid money-market mutual funds. Our restricted cash balance reflects the portion of net proceeds from the issuance of our senior secured term loan which are currently held in a restricted account until the completion of certain administrative tasks related to providing access rights to certain of our real property.

Other Receivables — Our other receivables primarily consist of recoverable taxes related to our international operations, as well as net income tax receivables.

Prepaid Expenses and Other Current Assets — Prepaid expenses and other current assets include items such as insurance, rent deposits, software subscriptions and other fees. We routinely expense these items in the normal course of business over the periods that we benefit from these expenses. Prepaid expenses and other current assets also include deferred mobilization costs for short-term drilling contracts.

Other Noncurrent Assets — Other noncurrent assets consist of deferred mobilization costs on long-term drilling contracts, cash deposits related to the deductibles on our workers’ compensation insurance policies, and deferred compensation plan investments.

Other Accrued Expenses — Our other accrued expenses include accruals for items such as sales taxes, property taxes, withholding tax liability related to our international operations, and professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Our other accrued expenses also includes the current portion of the lease liability associated with our long-term operating leases.

Other Noncurrent Liabilities — Our other noncurrent liabilities consist of the noncurrent portion of deferred mobilization revenues and liabilities associated with our long-term compensation plans.

2. Revenue from Contracts with Customers

Our production services business segments earn revenues for well servicing, wireline services and coiled tubing services pursuant to master services agreements based on purchase orders or other contractual arrangements with the client. Production services jobs are generally short-term (ranging in duration from several hours to less than 30 days) and are charged at current market rates for the labor, equipment and materials necessary to complete the job. Production services jobs are varied in nature, but typically represent a single performance obligation, either for a particular job, a series of distinct jobs, or a period of time during which we stand ready to provide services as our client needs them. Revenue is recognized for these services over time, as the services are performed.

Our drilling services business segments earn revenues by drilling oil and gas wells for our clients under daywork contracts. Daywork contracts are comprehensive agreements under which we provide a comprehensive service offering, including the drilling rig, crew, supplies and most of the ancillary equipment necessary to operate the rig. Contract modifications that extend the term of a dayrate contract are generally accounted for prospectively as a separate dayrate contract. We account for our services provided under daywork contracts as a single performance obligation comprised of a series of distinct time increments which are satisfied over time. Accordingly, dayrate revenues are recognized in the period during which the services are performed.

With most drilling contracts, we also receive payments contractually designated for the mobilization and demobilization of drilling rigs and other equipment to and from the client’s drill site. Revenues associated with the mobilization and demobilization of our drilling rigs to and from the client’s drill site do not relate to a distinct good or service and are recognized ratably over the related contract term.

The amount of demobilization revenue that we ultimately collect is dependent upon the specific contractual terms, most of which include provisions for reduced (or no) payment for demobilization when, among other things, the contract is renewed or extended with the same client, or when the rig is subsequently contracted with another client prior to the termination of the current contract. Since revenues associated with demobilization activity are typically variable, at each period end, they are estimated at the most likely amount, and constrained when the likelihood of a significant reversal is probable. Any change in the expected amount of demobilization revenue is accounted for with the net cumulative impact of the change in estimate recognized in the period during which the revenue estimate is revised.

The upfront costs that we incur to mobilize the drilling rig to our client’s initial drilling site are capitalized and recognized ratably over the term of the related contract, including any contracted renewal or extension periods, which is our estimate of the period during which we expect to benefit from the cost of mobilizing the rig. Costs associated with the final demobilization at the end of the contract term are expensed when incurred, when the demobilization activity is performed.

We also act as a principal for certain reimbursable services and auxiliary equipment provided by us to our clients, for which we incur costs and earn revenues, many of which are variable, or dependent upon the activity that is actually performed each day under the related contract. Accordingly, reimbursements that we receive for out-of-pocket expenses are recorded as revenues and the out-of-pocket expenses for which they relate are recorded as operating costs during the period to which they relate within the series of distinct time increments.

All of our revenues are recognized net of sales taxes, when applicable.

Contract Asset and Liability Balances and Contract Cost Assets

Contract asset and contract liability balances relate to demobilization and mobilization revenues, respectively. Demobilization revenue that we expect to receive is recognized ratably over the related contract term, but invoiced upon completion of the demobilization activity. Mobilization revenue, which is typically collected upon the completion of the initial mobilization activity, is deferred and recognized ratably over the related contract term. Contract asset and liability

balances are netted at the contract level, with the net current and noncurrent portions separately classified in our condensed consolidated balance sheets, and referred to herein as “deferred revenues.”

Contract cost assets represent the costs associated with the initial mobilization required in order to fulfill the contract, which are deferred and recognized ratably over the period during which we expect to benefit from the mobilization, or the period during which we expect to satisfy the performance obligations of the related contract. Contract cost assets are presented as either current or noncurrent, according to the duration of the original contract to which it relates, and referred to herein as “deferred costs.”

Our current and noncurrent deferred revenues and costs as of March 31, 2019 and December 31, 2018 were as follows (amounts in thousands):



	March 31, 2019		December 31, 2018
Current deferred revenues	$	1,659	$	1,722
Current deferred costs	1,621		1,543

Noncurrent deferred revenues	$	428	$	437
Noncurrent deferred costs	676		679

The changes in deferred revenue and cost balances during the three months March 31, 2019 are primarily related to increased deferred mobilization revenue and cost balances for the deployment of one international rig and two domestic rigs under new term contracts in 2019, mostly offset by the amortization of deferred revenues and costs during the period. Amortization of deferred revenues and costs during the three months ended March 31, 2019 and 2018 were as follows (amounts in thousands):



	Three months ended March 31,
	2019		2018
Amortization of deferred revenues	$	954	$	499
Amortization of deferred costs	986		463

In February 2019, one of our domestic clients elected to early terminate their contract with us and make an upfront early termination payment based on a per day rate for the remaining term of the contract, resulting in $0.4 million of revenues associated with the 34 days that were remaining under the contract term. We subsequently placed this rig with another client. As of March 31, 2019, all but one of our 25 rigs are earning under daywork contracts, 14 of which are domestic term contracts. Our international drilling contracts are cancelable by our clients without penalty, although the contracts require 15 to 30 days notice and payment for demobilization services. The spot contracts for our domestic drilling rigs are also terminable by our client with 30 days notice, but typically do not include a required payment for demobilization services.

3. Leases

As a drilling and production services provider, we provide the drilling rigs and production services equipment which are necessary to fulfill our performance obligations and which are considered leases under ASU No. 2016-02, Leases, (together with its amendments, herein referred to as “ASC Topic 842”). However, ASU No. 2018-11, Leases: Targeted Improvements, allows lessors to (i) combine the lease and non-lease components of revenues when the revenue recognition pattern is the same and when the lease component, when accounted for separately, would be considered an operating lease, and (ii) account for the combined lease and non-lease components under ASC Topic 606, Revenue from Contracts with Customers, when the non-lease component is the predominant element of the combined component. We elected to apply this expedient and therefore continue to recognize our revenues (both lease and service components) under ASC Topic 606, and continue to present them as one revenue stream in our unaudited condensed consolidated statements of operations.

As a lessee, we lease our corporate office headquarters in San Antonio, Texas, and we conduct our business operations through 28 other regional offices located throughout the United States and internationally in Colombia. These operating locations typically include regional offices, storage and maintenance yards and employee housing sufficient to support our operations in the area. We lease most of these properties under non-cancelable term and month-to-month operating leases, many of which contain renewal options that can extend the lease term from one to five years and some of which contain escalation clauses. We also lease supplemental equipment, typically under cancelable short-term and very short term (less than 30 days) leases. Due to the nature of our business, any option to renew these short-term leases, and the options to extend certain of our long-term real estate leases, are generally not considered reasonably certain to be exercised. Therefore,

the periods covered by such optional periods are not included in the determination of the term of the lease, and the lease payments during these periods are similarly excluded from the calculation of operating lease asset and lease liability balances.

In accordance with ASC Topic 842, we recognize an operating lease asset and a corresponding operating lease liability for all our long-term leases, which include real estate and office equipment leases, for which we elected to combine, or not separate, the lease and non-lease components, and therefore, all fixed charges associated with non-lease components are included in the lease payments and the calculation of the operating lease asset and associated lease liability. The operating lease asset and operating lease liability are discounted at the rate which represents our secured incremental borrowing rate, as most of our leases do not provide an implicit rate, and which we estimate based on the rate in effect under our asset-based lending facility.

We recognize rent expense on a straight-line basis, except for certain variable expenses which are recognized when the variability is resolved, typically during the period in which they are paid. Variable lease payments typically include charges for property taxes and insurance, and some leases contain variable payments related to non-lease components, including common area maintenance and usage of office equipment (for example, copiers), which totaled approximately $0.3 million during the three months ended March 31, 2019. The following table summarizes our lease expense recognized for the three months ending March 31, 2019, excluding variable lease costs (amounts in thousands):



Long-term operating lease expense	$	842
Short-term operating lease expense	$	3,403

The following table summarizes the amount and timing of our obligations associated with our long-term operating leases (amounts in thousands):



	March 31, 2019			December 31, 2018
Within 1 year	$	2,878		$	3,318
In the second year	2,045			2,032
In the third year	1,761			1,721
In the fourth year	1,355			1,407
In the fifth year	1,007			1,110
Thereafter	1,496			1,738
Total undiscounted lease obligations	$	10,542		$	11,326
Impact of discounting	(1,098		)
Discounted value of operating lease obligations	$	9,444

Current operating lease liabilities	$	2,515
Noncurrent operating lease liabilities	6,929
	$	9,444

The following table summarizes the weighted-average remaining lease term and discount rate associated with our long-term operating leases:



	March 31, 2019
Weighted-average remaining lease term (in years)	4.9
Weighted-average discount rate	4.5	%

4. Property and Equipment

Capital Expenditures — Our capital expenditures were $18.4 million and $14.6 million during the three months ended March 31, 2019 and 2018, respectively. Capital expenditures during the three months ended March 31, 2019 primarily related to various upgrades and refurbishments of our drilling and production services fleets, the completion of construction on our 17^th AC drilling rig which we deployed in March, and various vehicle and ancillary equipment purchases. Capital expenditures during the three months ended March 31, 2018 primarily related to the expansion of our wireline and coiled tubing fleets, upgrades and refurbishments to our international drilling rigs, and routine equipment and fleet maintenance.

At March 31, 2019, capital expenditures incurred for property and equipment not yet placed in service was $9.2 million, primarily related to capital projects to upgrade and refurbish certain components of our drilling rig fleet, support equipment for our coiled tubing unit fleet, and installments on two new wireline units on order at March 31, 2019, both of which were

received and placed in service in April. At December 31, 2018, property and equipment not yet placed in service was $19.6 million, primarily related to approximately $8.0 million of costs for the construction of a new-build drilling rig, various refurbishments and upgrades of drilling and production services equipment, and the purchase of other new ancillary equipment.

Gain/Loss on Disposition of Property — During the three months ended March 31, 2019, we recognized a net gain of $1.1 million on the disposition of various property and equipment. During the three months ended March 31, 2018, we recognized a net gain of $0.3 million on the disposition of various property and equipment, including the sale of six wireline units and one drilling rig, which was previously held for sale.

Assets Held for Sale — As of March 31, 2019 and December 31, 2018, our condensed consolidated balance sheet reflects assets held for sale of $4.8 million and $3.6 million, respectively, which includes the fair value of one domestic SCR drilling rig and related spare equipment and three coiled tubing units. Additionally, our March 31, 2019 assets held for sale also include the fair value of a building for one closed wireline location, 12 wireline units and spare coiled tubing equipment which were designated as held for sale in the first quarter of 2019.

During the three months ended March 31, 2019, we recognized impairment charges of $1.0 million to reduce the carrying values of assets which were classified as held for sale, to their estimated fair values, based on expected sales prices which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures.

Impairments — In accordance with ASC Topic 360, Property, Plant and Equipment, we monitor all indicators of potential impairments, and concluded there are no triggers present that require impairment testing as of March 31, 2019, other than the placement of certain assets as held for sale.

We evaluate for potential impairment of long-lived assets when indicators of impairment are present, which may include, among other things, significant adverse changes in industry trends (including revenue rates, utilization rates, oil and natural gas market prices, and industry rig counts). In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of the assets grouped at the lowest level that independent cash flows can be identified. We perform an impairment evaluation and estimate future undiscounted cash flows for each of our reporting units separately, which are our domestic drilling services, international drilling services, well servicing, wireline services and coiled tubing services segments. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we determine the fair value of the asset group, and the amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of the assets.

The most significant inputs used in our impairment analysis include the projected utilization and pricing of our services, as well as the estimated proceeds upon any future sale or disposal of the assets, all of which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. The assumptions we use in the evaluation for impairment are inherently uncertain and require management judgment. Although we believe the assumptions and estimates used in our impairment analysis are reasonable, different assumptions and estimates could materially impact the analysis and resulting conclusions.


5.	Valuation Allowances on Deferred Tax Assets

As of March 31, 2019, we had $98.1 million and $9.3 million of deferred tax assets related to domestic and foreign net operating losses, respectively, that are available to reduce future taxable income. Our domestic net operating losses will begin to expire in 2030, while losses generated after 2017 are carried forward indefinitely but are limited in usage to 80% of taxable income. The majority of our foreign net operating losses are carried forward indefinitely, but losses generated after 2016 are carried forward for 12 years and will begin to expire in 2029.

We provide a valuation allowance when it is more likely than not that some portion of the deferred tax assets will not be realized. As result, as of March 31, 2019, we had a valuation allowance of $66.4 million that offset a portion of our domestic and foreign net deferred tax assets.

Since 2017, market conditions and operating results for our Colombian operations have improved, and if they continue to improve, then we may determine that there is sufficient evidence that future taxable income will be generated to utilize our foreign net operating losses which would result in the reversal of the valuation allowance relating to our foreign deferred tax assets.

6. Debt

Our debt consists of the following (amounts in thousands):



	March 31, 2019			December 31, 2018
Senior secured term loan	$	175,000		$	175,000
Senior notes	300,000			300,000
	475,000			475,000
Less unamortized discount (based on imputed interest rate of 10.46%)	(2,475		)	(2,668		)
Less unamortized debt issuance costs	(7,210		)	(7,780		)
	$	465,315		$	464,552

Senior Secured Term Loan

Our senior secured term loan (the “Term Loan”) entered into on November 8, 2017 provided for one drawing in the amount of $175 million, net of a 2% original issue discount. Proceeds from the issuance of the Term Loan were used to repay the entire outstanding balance under our previous credit facility, plus fees and accrued and unpaid interest, as well as the fees and expenses associated with entering into the Term Loan and ABL Facility, which is further described below. The remainder of the proceeds are available to be used for other general corporate purposes.

The Term Loan is not subject to amortization payments of principal. Interest on the principal amount accrues at the LIBOR rate or the base rate as defined in the agreement, at our option, plus an applicable margin of 7.75% and 6.75%, respectively. The Term Loan is set to mature on November 8, 2022, or earlier, subject to certain circumstances as described in the agreement, and including an earlier maturity date if the outstanding balance of the Senior Notes exceeds $15.0 million on December 14, 2021, at which time the Term Loan would then mature. However, the Term Loan may be prepaid, at our option, at any time, in whole or in part, subject to a minimum of $5 million, and subject to a declining call premium as defined in the agreement.

The Term Loan contains a financial covenant requiring the ratio of (i) the net orderly liquidation value of our fixed assets (based on appraisals obtained as required by our lenders), on a consolidated basis, in which the lenders under the Term Loan maintain a first priority security interest, plus proceeds of asset dispositions not required to be used to effect a prepayment of the Term Loan to (ii) the outstanding principal amount of the Term Loan, to be at least equal to 1.50 to 1.00 as of any June 30 or December 31 of any calendar year through maturity.


•	incur additional debt;


•	incur or permit liens on assets;


•	make investments and acquisitions;


•	consolidate or merge with another company;


•	engage in asset sales; and


•	pay dividends or make distributions.

In addition, the Term Loan contains customary events of default, upon the occurrence and during the continuation of any of which the applicable margin would increase by 2% per year, including without limitation:


•	payment defaults;


•	covenant defaults;


•	material breaches of representations or warranties;


•	event of default under, or acceleration of, other material indebtedness;


•	bankruptcy or insolvency;


•	material judgments against us;


•	failure of any security document supporting the Term Loan; and


•	change of control.

Our obligations under the Term Loan are guaranteed by our wholly-owned domestic subsidiaries, and are secured by substantially all of our domestic assets, in each case, subject to certain exceptions and permitted liens.

Asset-based Lending Facility

In addition to entering into the Term Loan, on November 8, 2017, we also entered into a senior secured revolving asset-based credit facility (the “ABL Facility”) providing for borrowings in the aggregate principal amount of up to $75 million, subject to a borrowing base and including a $30 million sub-limit for letters of credit. The ABL Facility bears interest, at our option, at the LIBOR rate or the base rate as defined in the ABL Facility, plus an applicable margin ranging from 1.75% to 3.25%, based on average availability on the ABL Facility. The ABL Facility requires a commitment fee due monthly based on the average monthly unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a monthly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period. The ABL Facility is generally set to mature 90 days prior to the maturity of the Term Loan, subject to certain circumstances, including the future repayment, extinguishment or refinancing of our Term Loan and/or Senior Notes prior to their respective maturity dates. Availability under the ABL Facility is determined by reference to a borrowing base as defined in the agreement, generally comprised of a percentage of our accounts receivable and inventory.

We have not drawn upon the ABL Facility to date. As of March 31, 2019, we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $58.7 million. Borrowings available under the ABL Facility are available for general corporate purposes, and there are no limitations on our ability to access the borrowing capacity provided there is no default and compliance with the covenants under the ABL Facility is maintained. Additionally, if our availability under the ABL Facility is less than 15% of the maximum amount (or $11.25 million), we are required to maintain a minimum fixed charge coverage ratio, as defined in the ABL Facility, of at least 1.00 to 1.00, measured on a trailing 12 month basis.

The ABL Facility also contains customary restrictive covenants which, subject to certain exceptions, limit, among other things, our ability to:


•	declare dividends and make other distributions;


•	issue or sell certain equity interests;


•	optionally prepay, redeem or repurchase certain of our subordinated indebtedness;


•	make loans or investments (including acquisitions);


•	incur additional indebtedness or modify the terms of permitted indebtedness;


•	grant liens;


•	change our business or the business of our subsidiaries;


•	merge, consolidate, reorganize, recapitalize, or reclassify our equity interests;


•	sell our assets, and


•	enter into certain types of transactions with affiliates.

Our obligations under the ABL Facility are guaranteed by us and our domestic subsidiaries, subject to certain exceptions, and are secured by (i) a first-priority perfected security interest in all inventory and cash, and (ii) a second-priority perfected security in substantially all of our tangible and intangible assets, in each case, subject to certain exceptions and permitted liens.

Senior Notes

In 2014, we issued $300 million of unregistered senior notes at face value, with a coupon interest rate of 6.125% that are due in 2022 (the “Senior Notes”). The Senior Notes will mature on March 15, 2022 with interest due semi-annually in arrears on March 15 and September 15 of each year. We have the option to redeem the Senior Notes, in whole or in part, in each case at the redemption price specified in the Indenture dated March 18, 2014 (the “Indenture”) plus any accrued and unpaid interest and any additional interest (as defined in the Indenture) thereon to the date of redemption.

In accordance with a registration rights agreement with the holders of our Senior Notes, we filed an exchange offer registration statement on Form S-4 with the Securities and Exchange Commission that became effective on October 2, 2014. The exchange offer registration statement enabled the holders of our Senior Notes to exchange their senior notes for publicly registered notes with substantially identical terms. References to the “Senior Notes” herein include the senior notes issued in the exchange offer.

If we experience a change of control (as defined in the Indenture), we will be required to make an offer to each holder of the Senior Notes to repurchase all or any part of the Senior Notes at a purchase price equal to 101% of the principal amount of each Senior Note, plus accrued and unpaid interest, if any, to the date of repurchase. If we engage in certain asset sales, within 365 days of such sale we will be required to use the net cash proceeds from such sale, to the extent we do not reinvest those proceeds in our business, to make an offer to repurchase the Senior Notes at a price equal to 100% of the principal amount of each Senior Note, plus accrued and unpaid interest to the repurchase date.

The Indenture, among other things, limits us and certain of our subsidiaries, subject to certain exceptions, in our ability to:


•	pay dividends on stock, repurchase stock, redeem subordinated indebtedness or make other restricted payments and investments;


•	incur, assume or guarantee additional indebtedness or issue preferred or disqualified stock;


•	create liens on our or their assets;


•	enter into sale and leaseback transactions;


•	sell or transfer assets;


•	borrow, pay dividends, or transfer other assets from certain of our subsidiaries;


•	consolidate with or merge with or into, or sell all or substantially all of our properties to any other person;


•	enter into transactions with affiliates; and


•	enter into new lines of business.

The Senior Notes are not subject to any sinking fund requirements. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by certain of our future domestic subsidiaries. (See Note 12, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements.)

Debt Issuance Costs and Original Issue Discount

Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the effective interest method over the term of the Senior Notes which mature in March 2022. The original issue discount and costs incurred in connection with the issuance of the Term Loan were capitalized and are being amortized using the effective interest method over the expected term of the agreement. Costs incurred in connection with the ABL Facility were capitalized and are being amortized using the straight-line method over the expected term of the agreement.


7.	Fair Value of Financial Instruments

The FASB’s Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures, defines fair value and provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value. Our financial instruments consist primarily of cash and cash equivalents, trade and other receivables, trade payables, phantom stock unit awards and long-term debt.

The carrying value of cash and cash equivalents, trade and other receivables, and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments. At March 31, 2019 and December 31, 2018, the aggregate estimated fair value of our phantom stock unit awards was $10.3 million and $5.1 million, respectively, for which the vested portion recognized as a liability in our condensed consolidated balance sheets was $4.5 million and $3.6 million, respectively. The phantom stock unit awards, and the measurement of fair value for these awards, are described in more detail in Note 9, Stock-Based Compensation Plans.

The fair value of our Senior Notes is estimated based on recent observable market prices for our debt instruments, which are defined by ASC Topic 820 as Level 2 inputs. The fair value of our Term Loan is based on estimated market pricing for our debt instrument, which is defined by ASC Topic 820 as using Level 3 inputs which are unobservable and therefore more likely to be affected by changes in assumptions. The following table presents supplemental fair value information and carrying value for our debt, net of discount and debt issuance costs (amounts in thousands):



		March 31, 2019				December 31, 2018
	Hierarchy Level	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior notes	2	$	297,198	$	187,500	$	296,988	$	186,750
Senior secured term loan	3	168,117		$	175,875	167,564		175,875
		$	465,315	$	363,375	$	464,552	$	362,625


8.	Earnings (Loss) Per Common Share

The following table presents a reconciliation of the numerators and denominators of the basic earnings per share and diluted earnings per share computations (amounts in thousands, except per share data):



	Three months ended March 31,
	2019			2018
Numerator (both basic and diluted):
Net loss	$	(15,115	)	$	(11,139	)
Denominator:
Weighted-average shares (denominator for basic earnings (loss) per share)	78,311			77,606
Dilutive effect of outstanding stock options, restricted stock and restricted stock unit awards	—			—
Denominator for diluted earnings (loss) per share	78,311			77,606
Loss per common share - Basic	$	(0.19	)	$	(0.14	)
Loss per common share - Diluted	$	(0.19	)	$	(0.14	)
Potentially dilutive securities excluded as anti-dilutive	4,189			5,621


9.	Stock-Based Compensation Plans

We grant stock option and restricted stock awards with vesting based on time of service conditions. We grant restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions. We grant phantom stock unit awards with vesting based on time of service, performance and market conditions, which are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation since we expect to settle the awards in cash when they become vested.

We recognize compensation cost for our stock-based compensation awards based on the fair value estimated in accordance with ASC Topic 718, Compensation—Stock Compensation, and we recognize forfeitures when they occur. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards. The following table summarizes the stock-based compensation expense recognized, by award type, and the compensation expense recognized for phantom stock unit awards during the three months ended March 31, 2019 and 2018 (amounts in thousands):



	Three months ended March 31,
	2019		2018
Stock option awards	$	51	$	142
Restricted stock awards	114		113
Restricted stock unit awards	702		1,004
	$	867	$	1,259
Phantom stock unit awards	$	848	$	430

Stock Option Awards

We grant stock option awards which generally become exercisable over a three-year period and expire ten years after the date of grant. Our stock-based compensation plans require that all stock option awards have an exercise price that is not less than the fair market value of our common stock on the date of grant. We issue shares of our common stock when vested stock option awards are exercised. We estimate the fair value of each option grant on the date of grant using a Black-Scholes option pricing model. We did not grant any stock option awards during the three months ended March 31, 2019 or 2018.

Restricted Stock and Restricted Stock Unit Awards

We grant restricted stock awards that vest over a one-year period with a fair value based on the closing price of our common stock on the date of the grant. When restricted stock awards are granted, or when restricted stock unit awards are converted to restricted stock, shares of our common stock are considered issued, but subject to certain restrictions.

We grant restricted stock unit awards with vesting based on time of service conditions only (“time-based RSUs”), and we grant restricted stock unit awards with vesting based on time of service, which are also subject to performance and market conditions (“performance-based RSUs”). Shares of our common stock are issued to recipients of restricted stock units only when they have satisfied the applicable vesting conditions.

There were no restricted stock or performance-based restricted stock unit awards granted during the three months ended March 31, 2019 or 2018. The following table summarizes the number and weighted-average grant-date fair value of the restricted stock unit awards granted during the three months ended March 31, 2019 and 2018:



	Three months ended March 31,
	2019		2018
Time-based RSUs granted	870,648		788,377
Weighted-average grant-date fair value (per unit)	$	1.38	$	3.85

Our time-based RSUs generally vest over a three-year period, with fair values based on the closing price of our common stock on the date of grant. Our performance-based RSUs cliff vest at 39 months from the date of grant and are granted at a target number of issuable shares, for which the final number of shares of common stock is adjusted based on our actual achievement levels that are measured against predetermined performance conditions. The number of shares of common stock awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the performance period, generally three years. As of March 31, 2019, we estimate that the achievement level for our outstanding performance-based RSUs granted in 2017 will be approximately 100% of the predetermined performance conditions.

Phantom Stock Unit Awards

We grant phantom stock unit awards with vesting based on time of service, performance and market conditions. Time-based phantom stock unit awards, which were granted in 2019, vest annually in thirds over a three-year vesting period. Performance-based phantom stock unit awards, which were granted in 2016, 2018 and 2019, cliff-vest after 39 months from the date of grant, with vesting based on time of service, performance and market conditions. The number of performance-based units ultimately awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the respective three-year performance periods. Each unit awarded will entitle the employee to a cash payment equal to the stock price of our common stock on the date of vesting, subject to an applicable maximum payout feature that is based on a multiple of the grant date stock price.

The fair value of time-based phantom stock unit awards is measured using a Black-Scholes pricing model and the fair value of performance-based phantom stock unit awards is measured using a Monte Carlo simulation model, with inputs that are defined as Level 3 inputs under ASC Topic 820, Fair Value Measurements and Disclosures.

The following table summarizes the number, weighted-average grant-date fair value, and applicable maximum cash value of the phantom stock unit awards granted during the three months ended March 31, 2019 and 2018:



	Three months ended March 31,
	2019		2018
Performance-based:
Phantom stock unit awards granted	2,467,776		1,188,216
Weighted-average grant-date fair value (per unit)	$	1.10	$	3.06
Maximum cash value per unit (three times the grant date stock price)	$	4.62	$	9.66
Time-based:
Phantom stock unit awards granted	810,648		—
Weighted-average grant-date fair value (per unit)	$	1.17	$	—
Maximum cash value per unit (three times the grant date stock price)	$	4.62	$	—

These awards are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation, because we expect to settle the awards in cash when they vest, and are remeasured at fair value at the end of each reporting period until they vest. The change in fair value is recognized as a current period compensation expense in our condensed consolidated statements of operations. Therefore, changes in the inputs used to measure fair value can result in volatility in our compensation expense. This volatility increases as the phantom stock awards approach the vesting date. We estimate that a hypothetical increase of $1 in the market price of our common stock, which was $1.77 as of March 31, 2019, if all other inputs were unchanged, would result in an increase in cumulative compensation expense of $0.6 million, which represents the hypothetical increase in fair value of the liability for the 2018 and 2019 phantom stock unit awards. The maximum payout feature of these awards would limit this volatility if the stock price exceeds the maximum payout threshold. As of March 31, 2019, we estimate the weighted-average achievement level for our outstanding phantom stock unit awards granted in 2018 and 2019 to be 100%.

In April 2019, we determined that 175% of the target number of phantom stock unit awards granted during 2016 were earned based on the Company’s achievement of the performance measures, as compared to the predefined peer group, which resulted in an aggregate cash payment of $3.5 million to settle these awards.


10.	Segment Information

We have five operating segments, comprised of two drilling services business segments (domestic and international drilling) and three production services business segments (well servicing, wireline services and coiled tubing services), which reflects the basis used by management in making decisions regarding our business for resource allocation and performance assessment, as required by ASC Topic 280, Segment Reporting.

Our domestic and international drilling services segments provide contract land drilling services to a diverse group of exploration and production companies through our three drilling divisions in the US and internationally in Colombia. We provide a comprehensive service offering which includes the drilling rig, crews, supplies and most of the ancillary equipment needed to operate our drilling rigs.

Our well servicing, wireline services and coiled tubing services segments provide a range of production services to a diverse group of exploration and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Gulf Coast, Mid-Continent and Rocky Mountain states.

The following tables set forth certain financial information for each of our segments and corporate (amounts in thousands):



	As of and for the three months ended March 31,
	2019		2018
Revenues:
Domestic drilling	$	38,009	$	35,926
International drilling	21,643		17,611
Drilling services	59,652		53,537
Well servicing	26,254		21,114
Wireline services	45,874		56,601
Coiled tubing services	14,788		13,226
Production services	86,916		90,941
Consolidated revenues	$	146,568	$	144,478

Operating costs:
Domestic drilling	$	22,469	$	20,898
International drilling	16,485		12,961
Drilling services	38,954		33,859
Well servicing	18,896		15,570
Wireline services	39,347		42,486
Coiled tubing services	11,388		10,851
Production services	69,631		68,907
Consolidated operating costs	$	108,585	$	102,766

Gross margin:
Domestic drilling	$	15,540	$	15,028
International drilling	5,158		4,650
Drilling services	20,698		19,678
Well servicing	7,358		5,544
Wireline services	6,527		14,115
Coiled tubing services	3,400		2,375
Production services	17,285		22,034
Consolidated gross margin	$	37,983	$	41,712

Identifiable Assets:
Domestic drilling⁽¹⁾	$	377,239	$	380,382
International drilling ^{(1) (2)}	44,565		39,305
Drilling services	421,804		419,687
Well servicing	121,861		124,162
Wireline services	96,297		96,686
Coiled tubing services	40,810		30,824
Production services	258,968		251,672
Corporate	56,319		86,341
Consolidated identifiable assets	$	737,091	$	757,700

Depreciation:
Domestic drilling	$	10,545	$	10,449
International drilling	1,343		1,447
Drilling services	11,888		11,896
Well servicing	4,882		4,920
Wireline services	4,075		4,608
Coiled tubing services	1,528		2,032
Production services	10,485		11,560
Corporate	280		291
Consolidated depreciation	$	22,653	$	23,747



	As of and for the three months ended March 31,
	2019		2018
Capital Expenditures:
Domestic drilling	$	8,242	$	2,758
International drilling	1,758		2,700
Drilling services	10,000		5,458
Well servicing	3,895		2,049
Wireline services	2,835		3,673
Coiled tubing services	1,524		3,164
Production services	8,254		8,886
Corporate	121		244
Consolidated capital expenditures	$	18,375	$	14,588


(1)	Identifiable assets for our drilling segments include the impact of a $42.5 million and $31.5 million intercompany balance, as of March 31, 2019 and 2018 respectively, between our domestic drilling segment (intercompany receivable) and our international drilling segment (intercompany payable).


(2)	Identifiable assets for our international drilling segment include five drilling rigs that are owned by our Colombia subsidiary and three drilling rigs that are owned by one of our domestic subsidiaries and leased to our Colombia subsidiary.

The following table reconciles the consolidated gross margin of our segments reported above to loss from operations as reported on the condensed consolidated statements of operations (amounts in thousands):



	Three months ended March 31,
	2019			2018
Consolidated gross margin	$	37,983		$	41,712
Depreciation	(22,653		)	(23,747		)
General and administrative	(19,758		)	(19,194		)
Bad debt expense (recovery), net	(62		)	52
Impairment	(1,046		)	—
Gain on dispositions of property and equipment, net	1,075			335
Loss from operations	$	(4,461	)	$	(842	)


11.	Commitments and Contingencies

In connection with our operations in Colombia, our foreign subsidiaries routinely obtain bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $63.0 million relating to our performance under these bonds as of March 31, 2019. Based on historical experience and information currently available, we believe the likelihood of demand for payment under these bonds and guarantees is remote.

We are currently undergoing sales and use tax audits for multi-year periods. As of March 31, 2019 and December 31, 2018, our accrued liability was $1.8 million and $1.7 million, respectively, based on our estimate of the sales and use tax obligations that are expected to result from these audits. Due to the inherent uncertainty of the audit process, we believe that it is reasonably possible that we may incur additional tax assessments with respect to one or more of the audits in excess of the amount accrued. We believe that such an outcome would not have a material adverse effect on our results of operations or financial position. Because certain of these audits are in a preliminary stage, an estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

Due to the nature of our business, we are, from time to time, involved in litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Legal costs relating to these matters are expensed as incurred. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations.


12.	Guarantor/Non-Guarantor Condensed Consolidating Financial Statements

Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by all existing 100% owned domestic subsidiaries, except for Pioneer Services Holdings, LLC. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture.

In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of March 31, 2019, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.

As a result of the guarantee arrangements, we are presenting the following condensed consolidating balance sheets, statements of operations and statements of cash flows of the issuer, the guarantor subsidiaries and the non-guarantor subsidiaries.

CONDENSED CONSOLIDATING BALANCE SHEETS

(unaudited, in thousands)



	March 31, 2019
	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	24,400		$	—	$	2,455		$	—		$	26,855
Restricted cash	998			—		—			—			998
Receivables, net of allowance	380			108,312		39,959			(566		)	148,085
Intercompany receivable (payable)	(27,942		)	70,231		(42,289		)	—			—
Inventory	—			10,606		9,623			—			20,229
Assets held for sale	—			4,794		—			—			4,794
Prepaid expenses and other current assets	1,524			4,218		1,565			—			7,307
Total current assets	(640		)	198,161		11,313			(566		)	208,268
Net property and equipment	1,863			487,415		28,489			—			517,767
Investment in subsidiaries	584,449			27,789		—			(612,238		)	—
Deferred income taxes	42,659			—		—			(42,659		)	—
Operating lease assets	3,470			5,273		680			—			9,423
Other noncurrent assets	622			523		488			—			1,633
Total assets	$	632,423		$	719,161	$	40,970		$	(655,463	)	$	737,091
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,089		$	31,188	$	5,886		$	—		$	38,163
Deferred revenues	—			443		1,216			—			1,659
Accrued expenses	9,678			50,451		5,191			(566		)	64,754
Total current liabilities	10,767			82,082		12,293			(566		)	104,576
Long-term debt, less unamortized discount and debt issuance costs	465,315			—		—			—			465,315
Noncurrent operating lease liabilities	3,076			3,322		531			—			6,929
Deferred income taxes	—			47,503		—			(42,659		)	4,844
Other noncurrent liabilities	2,298			1,805		357			—			4,460
Total liabilities	481,456			134,712		13,181			(43,225		)	586,124
Total shareholders’ equity	150,967			584,449		27,789			(612,238		)	150,967
Total liabilities and shareholders’ equity	$	632,423		$	719,161	$	40,970		$	(655,463	)	$	737,091

	December 31, 2018
	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	50,350		$	—	$	3,216		$	—		$	53,566
Restricted cash	998			—		—			—			998
Receivables, net of allowance	436			95,030		35,219			196			130,881
Intercompany receivable (payable)	(27,245		)	67,098		(39,853		)	—			—
Inventory	—			9,945		8,953			—			18,898
Assets held for sale	—			3,582		—			—			3,582
Prepaid expenses and other current assets	1,743			3,197		2,169			—			7,109
Total current assets	26,282			178,852		9,704			196			215,034
Net property and equipment	2,022			494,376		28,460			—			524,858
Investment in subsidiaries	574,695			25,370		—			(600,065		)	—
Deferred income taxes	42,585			—		—			(42,585		)	—
Other noncurrent assets	596			511		551			—			1,658
Total assets	$	646,180		$	699,109	$	38,715		$	(642,454	)	$	741,550
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,093		$	26,795	$	6,246		$	—		$	34,134
Deferred revenues	—			95		1,627			—			1,722
Accrued expenses	14,020			49,640		5,056			196			68,912
Total current liabilities	15,113			76,530		12,929			196			104,768
Long-term debt, less unamortized discount and debt issuance costs	464,552			—		—			—			464,552
Deferred income taxes	—			46,273		—			(42,585		)	3,688
Other noncurrent liabilities	1,457			1,611		416			—			3,484
Total liabilities	481,122			124,414		13,345			(42,389		)	576,492
Total shareholders’ equity	165,058			574,695		25,370			(600,065		)	165,058
Total liabilities and shareholders’ equity	$	646,180		$	699,109	$	38,715		$	(642,454	)	$	741,550

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(unaudited, in thousands)



	Three months ended March 31, 2019
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	124,925		$	21,643		$	—		$	146,568
Costs and expenses:
Operating costs	—			92,102			16,483			—			108,585
Depreciation	280			21,030			1,343			—			22,653
General and administrative	7,996			11,446			451			(135		)	19,758
Bad debt expense (recovery), net	—			62			—			—			62
Gain on dispositions of property and equipment, net	—			(984		)	(91		)	—			(1,075		)
Impairment	—			1,046			—			—			1,046
Intercompany leasing	—			(1,215		)	1,215			—			—
Total costs and expenses	8,276			123,487			19,401			(135		)	151,029
Income (loss) from operations	(8,276		)	1,438			2,242			135			(4,461		)
Other income (expense):
Equity in earnings of subsidiaries	2,768			2,464			—			(5,232		)	—
Interest expense, net of interest capitalized	(9,874		)	(14		)	3			—			(9,885		)
Other	206			266			347			(135		)	684
Total other income (expense)	(6,900		)	2,716			350			(5,367		)	(9,201		)
Income (loss) before income taxes	(15,176		)	4,154			2,592			(5,232		)	(13,662		)
Income tax (expense) benefit ¹	61			(1,386		)	(128		)	—			(1,453		)
Net income (loss)	$	(15,115	)	$	2,768		$	2,464		$	(5,232	)	$	(15,115	)

	Three months ended March 31, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	126,867		$	17,611		$	—		$	144,478
Costs and expenses:
Operating costs	—			89,809			12,957			—			102,766
Depreciation	291			22,009			1,447			—			23,747
General and administrative	6,238			12,539			522			(105		)	19,194
Bad debt expense (recovery), net	—			(52		)	—			—			(52		)
Gain on dispositions of property and equipment, net	—			(321		)	(14		)	—			(335		)
Intercompany leasing	—			(1,215		)	1,215			—			—
Total costs and expenses	6,529			122,769			16,127			(105		)	145,320
Income (loss) from operations	(6,529		)	4,098			1,484			105			(842		)
Other income (expense):
Equity in earnings of subsidiaries	4,549			1,653			—			(6,202		)	—
Interest expense, net of interest capitalized	(9,516		)	—			3			—			(9,513		)
Other	2			219			388			(105		)	504
Total other income (expense)	(4,965		)	1,872			391			(6,307		)	(9,009		)
Income (loss) before income taxes	(11,494		)	5,970			1,875			(6,202		)	(9,851		)
Income tax (expense) benefit ¹	355			(1,421		)	(222		)	—			(1,288		)
Net income (loss)	$	(11,139	)	$	4,549		$	1,653		$	(6,202	)	$	(11,139	)

¹ The income tax (expense) benefit reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(unaudited, in thousands)



	Three months ended March 31, 2019
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities	$	(18,807	)	$	7,603		$	414		$	—	$	(10,790	)

Cash flows from investing activities:
Purchases of property and equipment	(162		)	(15,496		)	(1,186		)	—		(16,844		)
Proceeds from sale of property and equipment	—			987			56			—		1,043
	(162		)	(14,509		)	(1,130		)	—		(15,801		)

Cash flows from financing activities:
Purchase of treasury stock	(120		)	—			—			—		(120		)
Intercompany contributions/distributions	(6,861		)	6,906			(45		)	—		—
	(6,981		)	6,906			(45		)	—		(120		)

Net decrease in cash, cash equivalents and restricted cash	(25,950		)	—			(761		)	—		(26,711		)
Beginning cash, cash equivalents and restricted cash	51,348			—			3,216			—		54,564
Ending cash, cash equivalents and restricted cash	$	25,398		$	—		$	2,455		$	—	$	27,853

	Three months ended March 31, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities	$	(15,289	)	$	17,992		$	2,355		$	—	$	5,058

Cash flows from investing activities:
Purchases of property and equipment	(179		)	(8,978		)	(2,500		)	—		(11,657		)
Proceeds from sale of property and equipment	—			1,283			—			—		1,283
Proceeds from insurance recoveries	—			508			15			—		523
	(179		)	(7,187		)	(2,485		)	—		(9,851		)

Cash flows from financing activities:
Debt issuance costs	(33		)	—			—			—		(33		)
Purchase of treasury stock	(96		)	—			—			—		(96		)
Intercompany contributions/distributions	10,860			(10,805		)	(55		)	—		—
	10,731			(10,805		)	(55		)	—		(129		)

Net decrease in cash, cash equivalents and restricted cash	(4,737		)	—			(185		)	—		(4,922		)
Beginning cash, cash equivalents and restricted cash	72,385			—			3,263			—		75,648
Ending cash, cash equivalents and restricted cash	$	67,648		$	—		$	3,078		$	—	$	70,726


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

Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements made in good faith that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, levels and volatility of oil and gas prices, the continued demand for drilling services or production services in the geographic areas where we operate, decisions about exploration and development projects to be made by oil and gas exploration and production companies, the highly competitive nature of our business, technological advancements and trends in our industry and improvements in our competitors' equipment, the loss of one or more of our major clients or a decrease in their demand for our services, future compliance with covenants under debt agreements, including our senior secured term loan, our senior secured revolving asset-based credit facility, and our senior notes, operating hazards inherent in our operations, the supply of marketable drilling rigs, well servicing rigs, coiled tubing units and wireline units within the industry, the continued availability of new components for drilling rigs, well servicing rigs, coiled tubing units and wireline units, the continued availability of qualified personnel, the success or failure of our acquisition strategy, the occurrence of cybersecurity incidents, the political, economic, regulatory and other uncertainties encountered by our operations, and changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2018, including under the headings “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part I and “Risk Factors” in Item 1A. These factors are not necessarily all the important factors that could affect us. Other unpredictable or unknown factors could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as of the date on which they are made and we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise. We advise our shareholders that they should (1) recognize that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

Company Overview

Pioneer Energy Services Corp. provides land-based drilling services and production services to a diverse group of oil and gas exploration and production companies in the United States and internationally in Colombia. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well.

•

Drilling Services— Our current drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling. We have 17 AC rigs in the US and eight SCR rigs in Colombia, all of which have 1,500 horsepower or greater drawworks. We provide a comprehensive service offering which includes the drilling rig, crews, supplies and most of the ancillary equipment needed to operate our drilling rigs which are deployed through our division offices in the following regions:



		Rig Count
Domestic drilling:
Marcellus/Utica		6
Permian Basin and Eagle Ford		9
Bakken		2
International drilling		8
		25


•	Production Services— Our production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of exploration and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Gulf Coast, Mid-Continent and Rocky Mountain states.

•

Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to provide these necessary services, including the completion of newly-drilled wells, maintenance and workover of active wells, and plugging and abandonment of wells at the end of their useful lives. As of March 31, 2019, we have a fleet of 113 rigs with 550 horsepower and 12 rigs with 600 horsepower with operations in 10 locations, mostly in the Gulf Coast states, as well as in North Dakota and Colorado.

•

Wireline Services. Oil and gas exploration and production companies require wireline services to better understand the reservoirs they are drilling or producing, and use logging services to accurately characterize reservoir rocks and fluids. To complete a cased-hole well, the production casing must be perforated to establish a flow path between the reservoir and the wellbore. We use our fleet of wireline units to provide these important logging and perforating services in addition to a range of other mechanical services that are needed in order to place equipment in or retrieve equipment or debris from the wellbore, install bridge plugs and control pressure. As of March 31, 2019, we have a fleet of 93 wireline units, which are deployed through 12 operating locations in the Gulf Coast, Mid-Continent and Rocky Mountain states.

•

Coiled Tubing Services. Coiled tubing is another important element of the well servicing industry that allows operators to continue production during service operations on a well under pressure without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous flexible metal pipe which is spooled on a large reel and inserted into the wellbore to perform a variety of oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications, such as milling temporary plugs between frac stages. As of March 31, 2019, we have a current fleet of nine coiled tubing units, the majority of which offer larger diameter coil (larger than two inches), deployed through two operating locations that provide services in Texas, Wyoming and surrounding areas.

Pioneer Energy Services Corp. was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Since then, we have significantly expanded and transformed our business through acquisitions and organic growth. Our business is comprised of two business lines — Drilling Services and Production Services. We report our Drilling Services business as two reportable segments: (i) Domestic Drilling and (ii) International Drilling. We report our Production Services business as three reportable segments: (i) Well Servicing, (ii) Wireline Services, and (iii) Coiled Tubing Services. Financial information about our operating segments is included in Note 10, Segment Information, of the Notes to Unaudited Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

Pioneer Energy Services Corp.’s corporate office is located at 1250 N.E. Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (855) 884-0575 and our website address is www.pioneeres.com. We make available free of charge through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission (SEC). Information on our website is not incorporated into this report or otherwise made part of this report.

Market Conditions in Our Industry

Industry Overview — Demand for oilfield services offered by our industry is a function of our clients’ willingness to make operating expenditures and capital expenditures to explore for, develop and produce hydrocarbons, which is primarily driven by current and expected oil and natural gas prices.

Our business is influenced substantially by exploration and production companies’ spending that is generally categorized as either a capital expenditure or an operating expenditure. Capital expenditures for the drilling and completion of exploratory and development wells in proven areas are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices. In contrast, operating expenditures for the maintenance of existing wells, for which a range of production services are required in order to maintain production, are relatively more stable and predictable.

Drilling and production services have historically trended similarly in response to fluctuations in commodity prices. However, because exploration and production companies often adjust their budgets for exploration and development drilling first in response to a change in commodity prices, the demand for drilling services is generally impacted first and to a greater extent than the demand for production services which is more dependent on ongoing expenditures that are necessary to maintain production. Additionally, within the range of production services businesses, those that derive more revenue from production related activity, as opposed to completion of new wells, tend to be less affected by fluctuations in commodity prices and temporary reductions in industry activity.

However, in a severe downturn that is prolonged, both operating and capital expenditures are significantly reduced, and the demand for all our service offerings is significantly impacted. After a prolonged downturn, among the production services, the demand for completion-oriented services generally improves first, as exploration and production companies begin to complete wells that were previously drilled but not completed during the downturn, and to complete newly drilled wells as the demand for drilling services improves during recovery.

From time to time, temporary regional slowdowns or constraints occur in our industry due to a variety of factors, including, among others, infrastructure or takeaway capacity limitations, labor shortages, increased regulatory or environmental pressures, or an influx of competitors in a particular region. Any of these factors can influence the profitability of operations in the affected region. However, term contract coverage for our drilling services business and the mobility of all our equipment between regions reduces our exposure to the impact of regional constraints and fluctuations in demand.

Technological advancements and trends in our industry also affect the demand for certain types of equipment, and can affect the overall demand for the services our industry provides. Enhanced directional and horizontal drilling techniques have allowed exploration and production operators to drill increasingly longer lateral wellbores which enable higher hydrocarbon production per well, and reduce the overall number of wells needed to achieve the desired production. This trend toward longer lateral wellbores also increases demand for the more specialized equipment, such as high-spec drilling rigs, higher horsepower well servicing rigs equipped with taller masts, larger diameter coiled tubing units, and other higher power ancillary equipment, which is needed in order to drill, complete and provide services to the full length of the wellbore. Our domestic drilling and production services fleets are highly capable and designed for operation in today’s long lateral, pad-oriented environment.

For additional information concerning the potential effects of volatility in oil and gas prices and other industry trends, see Item 1A – “Risk Factors” in Part I of our Annual Report on Form 10-K for the year ended December 31, 2018.

Market Conditions — Our industry experienced a severe down cycle from late 2014 through 2016, during which WTI oil prices dipped below $30 per barrel in early 2016. A modest recovery in commodity prices began in the latter half of 2016 with WTI oil prices steadily increasing from just under $50 per barrel at the end of June 2016 to approximately $60 per barrel at the end of 2017. In 2018, WTI oil prices continued to increase to a high of $75 per barrel in October, but then decreased to $45 per barrel at the end of 2018. The average WTI oil price in the first quarter of 2019 increased to approximately $55 per barrel.

The trends in spot prices of WTI crude oil and Henry Hub natural gas, and the resulting trends in domestic land rig counts (per Baker Hughes) and domestic well servicing rig counts (per Guiberson/Association of Energy Service Companies) over the last three years are illustrated in the graphs below.

The trends in commodity pricing and domestic rig counts over the last 12 months are illustrated below:

As of March 31, 2019, 24 of our 25 drilling rigs are earning revenues, 20 of which are under term contracts, which if not canceled or renewed prior to the end of their terms, will expire as follows:



	Spot Market Contracts		Term Contract Expiration by Period
	Spot Market Contracts	Total Term Contracts	Within 6 Months	6 Months to 1 Year	1 Year to 18 Months	18 Months to 2 Years	2 to 4 Years
Domestic rigs	3	14	6	6	—	1	1
International rigs	1	6	2	1	2	1	—
	4	20	8	7	2	2	1

Our international drilling contracts are cancelable by our clients without penalty, although the contracts require 15 to 30 days notice and payment for demobilization services. We are actively marketing our idle rig in Colombia, and we also continue to evaluate the possibility of selling some or all of our assets in Colombia.

During the quarter ended March 31, 2019, our well servicing rig hours increased by 7%, while the number of wireline jobs completed and revenue days for our coiled tubing services were consistent, as compared to the fourth quarter of 2018. However, average revenue rates for our coiled tubing and wireline services provided during this same period increased by 15% and 6% (on a per job and per day basis, respectively), while average revenues per hour for our well servicing decreased slightly by 2%. The increase in coiled tubing revenues is primarily attributable to an increase in the proportion of work performed by our large-diameter coiled tubing units, which generally earn higher revenue rates as compared to smaller diameter coiled tubing units, while the increases in wireline and well servicing revenues were primarily due to an increase in completion activity.

The level of exploration and production activity within a region can fluctuate due to a variety of factors which may directly or indirectly impact our operations in the region. Despite the recovery of demand experienced in onshore markets, offshore activity remained depressed, and as a result, we exited the offshore wireline and coiled tubing market in the second quarter of 2018. In the Permian Basin, limited takeaway capacity has led to price discounts on crude oil that could continue to impact activity and near-term growth in the region; however, eight of our nine drilling rigs currently operating in this region are under term contracts, which helps to reduce our exposure to the impact of pricing fluctuations in this region. In Colorado, Senate Bill 19-181 was enacted in April, which gives the state’s oil and gas conservation commission and the state’s local governments more authority over oil and gas operations, and which could lead to newly imposed regulations that may impede our clients’ ability to operate in the region, and similarly reduce demand for the services that we provide in this region. At the end of March 2019, we were operating eleven wireline units and five well servicing rigs in Colorado, which we believe can be redeployed to other markets should future regulations negatively impact demand.

Although we expect a highly competitive environment to continue in all the areas in which we operate, we believe our high-quality equipment and services and our excellent safety record position us well to compete.

Liquidity and Capital Resources

Sources of Capital Resources

Our principal sources of liquidity currently consist of:


•	total cash and cash equivalents ($27.9 million as of March 31, 2019);


•	cash generated from operations;


•	proceeds from sales of assets; and


•	the availability under our asset-based lending facility ($58.7 million as of March 31, 2019).

Our asset-based lending facility (the “ABL Facility”) provides for a senior secured revolving asset-based credit facility, with sub-limits for letters of credit, of up to a current aggregate commitment amount of $75 million, subject to availability under a borrowing base generally comprised of a percentage of our accounts receivable and inventory. The ABL Facility is generally set to mature 90 days prior to the maturity of the Term Loan, subject to certain circumstances, including the future repayment, extinguishment or refinancing of our Term Loan and/or Senior Notes prior to their respective maturity dates.

We have not drawn upon our ABL Facility to date. As of March 31, 2019, we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $58.7 million. Borrowings available under the ABL Facility are available for general corporate purposes, and there are no limitations on our ability to access the borrowing capacity provided there is no default and compliance with the covenants under the ABL Facility is maintained. Additional information regarding these covenants is provided in the Debt Compliance Requirements section below.

In the future, we may also consider equity and/or debt offerings, as appropriate, to meet our liquidity needs. On May 22, 2018, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of March 31, 2019, the entire $300 million under the shelf registration statement is available for equity or debt offerings, subject to the limitations imposed by our Term Loan, ABL Facility and Senior Notes.

We currently expect that cash and cash equivalents, cash generated from operations, proceeds from sales of assets, and available borrowings under our ABL Facility are adequate to cover our liquidity requirements for at least the next 12 months.

Uses of Capital Resources

Our principal liquidity requirements are currently for:


•	working capital needs;


•	debt service; and


•	capital expenditures.

Our operations have historically generated cash flows sufficient to meet our requirements for debt service and normal capital expenditures. However, our working capital requirements generally increase during periods when rig construction projects are in progress or during periods of expansion in our production services business, at which times we have been more likely to access capital through equity or debt financing. Additionally, our working capital needs may increase in periods of increasing activity following a sustained period of low activity. During periods of sustained low activity and pricing, we may also access additional capital through the use of available funds under our ABL Facility.

Working Capital — Our working capital was $103.7 million at March 31, 2019, compared to $110.3 million at December 31, 2018. Our current ratio, which we calculate by dividing current assets by current liabilities, was 2.0 at March 31, 2019, as compared to 2.1 at December 31, 2018. The changes in the components of our working capital were as follows (amounts in thousands), and as described below:



	March 31, 2019		December 31, 2018		Change
Cash and cash equivalents	$	26,855	$	53,566	$	(26,711	)
Restricted cash	998		998		—
Receivables:
Trade, net of allowance for doubtful accounts	90,816		76,924		13,892
Unbilled receivables	27,535		24,822		2,713
Insurance recoveries	23,427		23,656		(229		)
Other receivables	6,307		5,479		828
Inventory	20,229		18,898		1,331
Assets held for sale	4,794		3,582		1,212
Prepaid expenses and other current assets	7,307		7,109		198
Current assets	208,268		215,034		(6,766		)
Accounts payable	38,163		34,134		4,029
Deferred revenues	1,659		1,722		(63		)
Accrued expenses:
Payroll and related employee costs	24,699		24,598		101
Insurance claims and settlements	22,819		23,593		(774		)
Insurance premiums and deductibles	5,543		5,482		61
Interest	1,460		6,148		(4,688		)
Other	10,233		9,091		1,142
Current liabilities	104,576		104,768		(192		)
Working capital	$	103,692	$	110,266	$	(6,574	)


•	Cash and cash equivalents — The change in cash and cash equivalents during 2019 is primarily due to $16.8 million of cash used for the purchase of property and equipment as well as $10.8 million of cash used in operating activities, offset slightly by $1.0 million of proceeds from the sale of property and equipment.

•

Trade and unbilled receivables — The net increase in our total trade and unbilled receivables during 2019 is due to lengthened collection cycles in our domestic segments, the timing of the billing and collection cycles for long-term drilling contracts in Colombia, and the 4% increase in our revenues during the quarter ended March 31, 2019, as compared to the quarter ended December 31, 2018. Our domestic trade receivables generally turn over within 60 days, and our Colombian trade receivables generally turn over within 120 days.


•	Inventory — The increase in inventory during 2019 is due to an increase in inventory for our international operations and purchases of supplies and job materials for our wireline operations.

•

Assets held for sale — As of March 31, 2019 and December 31, 2018, our condensed consolidated balance sheet reflects assets held for sale of $4.8 million and $3.6 million, respectively, which includes the fair value of one domestic SCR drilling rig and related spare equipment and three coiled tubing units. Additionally, our March 31, 2019 assets held for sale also includes the fair value of a building for one closed wireline location, 12 wireline units and spare coiled tubing equipment which were designated as held for sale in the first quarter of 2019. For additional information, see Note 4, Property and Equipment of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.


•	Accounts payable — Our accounts payable generally turn over within 90 days. The increase in accounts payable during 2019 is primarily due to lengthened payment cycles, the 4% increase in our operating costs for the quarter ended March 31, 2019 as compared to the quarter ended December 31, 2018, and a $1.5 million increase in our accruals for capital expenditures.


•	Accrued payroll and related employee costs — The change in accrued payroll and related employee costs during 2019 primarily resulted from an increase in accrued costs due to the timing of pay periods and a decrease in annual incentive compensation associated with the payment of 2018 annual bonuses which were fully accrued at December 31, 2018 and were paid in the first quarter of 2019.


•	Accrued interest — The decrease in accrued interest expense during 2019 is primarily due to the payment of interest on our Senior Notes which is due semi-annually on March 15 and September 15.

•

Other accrued expenses — The increase in other accrued expenses during 2019 is primarily due to the recognition of $2.5 million of current operating lease liabilities upon our adoption of ASU No. 2016-02, Leases, and its related amendments, as of January 1, 2019. For additional information about adoption of this standard, see Note 1, Organization and Summary of Significant Accounting Policies and Note 3, Leases, of the Notes to Unaudited Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q. The increase is partially offset, however, by a decrease in property and sales tax accruals due to the timing of payments.

Debt and Other Contractual Obligations — The following table includes information about the amount and timing of our contractual obligations at March 31, 2019 (amounts are undiscounted and in thousands):



	Payments Due by Period
Contractual Obligations	Total		Within 1 Year		2 to 3 Years		4 to 5 Years		Beyond 5 Years
Debt	$	475,000	$	—	$	475,000	$	—	$	—
Interest on debt	104,213		36,225		67,988		—		—
Purchase commitments	9,679		9,679		—		—		—
Operating leases	10,542		2,878		3,806		2,362		1,496
Incentive compensation	23,630		8,370		11,824		3,436		—
	$	623,064	$	57,152	$	558,618	$	5,798	$	1,496


•	Debt — Debt obligations at March 31, 2019 consist of $300 million of principal amount outstanding under our Senior Notes which mature on March 15, 2022 and $175 million of principal amount outstanding under our Term Loan which is expected to mature December 14, 2021. As of March 31, 2019, we had no debt outstanding under our ABL Facility.

•

Interest on debt — Interest payment obligations on our Senior Notes are calculated based on the coupon interest rate of 6.125% due semi-annually in arrears on March 15 and September 15 of each year until maturity on March 15, 2022. Interest payment obligations on our Term Loan were estimated based on (1) the 10.2% interest rate that was in effect at March 31, 2019, and (2) the principal balance of $175 million at March 31, 2019, and assuming repayment of the outstanding balance occurs at December 14, 2021.

•

Purchase commitments — Purchase commitments generally relate to capital projects for the repair, upgrade and maintenance of our equipment, the construction or purchase of new equipment, and purchase orders for various job and inventory supplies. At March 31, 2019, our purchase commitments primarily pertain to $3.6 million of service equipment for our coiled tubing operations and $2.7 million of inventory and job supplies for our coiled tubing operations. Other purchase commitments include drilling equipment on order as well as various refurbishments and upgrades to our drilling and production services fleets.


•	Operating leases — Our operating lease obligations relate to long-term lease agreements for office space, operating facilities, field personnel housing, and office equipment.

•

Incentive compensation — Incentive compensation is payable to our employees, generally contingent upon their continued employment through the date of each respective award’s payout. A portion of our long-term incentive compensation is performance-based and therefore the final amount will be determined based on our actual performance relative to a pre-determined peer group over the performance period. In April 2019, we determined that 175% of the target number of phantom stock unit awards granted during 2016 were earned based on the Company’s achievement of the performance measures, as compared to the predefined peer group, which resulted in an aggregate cash payment of $3.5 million to settle these awards, and which is included in the table above as an obligation due within one year.

Debt Compliance Requirements — The following is a summary of our debt compliance requirements including covenants, restrictions and guarantees, all of which are described in more detail in Note 6, Debt, and Note 12, Guarantor/Non-Guarantor

Condensed Consolidating Financial Statements, of the Notes to Unaudited Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

The Term Loan contains customary mandatory prepayments from the proceeds of certain transactions including certain asset dispositions and debt issuances, and has additional customary restrictions that limit our ability to enter into various transactions. In addition, the Term Loan contains customary events of default, upon the occurrence and during the continuation of any of which the applicable margin would increase by 2% per year. Our obligations under the Term Loan are guaranteed by our wholly-owned domestic subsidiaries, and are secured by substantially all of our domestic assets, in each case, subject to certain exceptions and permitted liens.

The ABL Facility also contains customary restrictive covenants which, subject to certain exceptions, limit, among other things, our ability to enter into certain transactions. Additionally, if our availability under the ABL Facility is less than 15% of the maximum amount (or $11.25 million), we are required to maintain a minimum fixed charge coverage ratio, as defined in the ABL Facility, of at least 1.00 to 1.00, measured on a trailing 12 month basis.

The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by certain of our future domestic subsidiaries. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. Our Senior Notes are not subject to any sinking fund requirements. The Indenture governing our Senior Notes contains additional restrictive covenants that limit our ability to enter into various transactions.

As of March 31, 2019, we were in compliance with all covenants required by our Term Loan, ABL Facility and Senior Notes.

Capital Expenditures — During the three months ended March 31, 2019, we spent $16.8 million on purchases of property and equipment and placed into service property and equipment of $18.4 million. Currently, we expect to spend approximately $55 to $60 million on capital expenditures during 2019, which includes approximately $7 million for final payments on the construction of the new-build drilling rig that began operations in the first quarter, and previous commitments on high-pressure pump packages for coiled tubing completion operations.

Actual capital expenditures may vary depending on the climate of our industry and any resulting increase or decrease in activity levels, the timing of commitments and payments, and the level of rig build and other expansion opportunities that meet our strategic and return on capital employed criteria. We expect to fund the remaining capital expenditures in 2019 from operating cash flow in excess of our working capital requirements, although proceeds from sales of assets, remaining proceeds from our Term Loan issuance, and available borrowings under our ABL Facility are also available, if necessary.

Results of Operations

Statements of Operations Analysis

The following table provides certain information about our operations, including details of each of our business segments’ revenues, operating costs and gross margin, and the percentage of the consolidated amount of each which is attributable to each business segment, for the three months ended March 31, 2019 and 2018 (amounts in thousands, except percentages):



	Three months ended March 31,
	2019					2018
Revenues:
Domestic drilling	$	38,009		26	%	$	35,926		25	%
International drilling	21,643			15	%	17,611			12	%
Drilling services	59,652			41	%	53,537			37	%
Well servicing	26,254			18	%	21,114			15	%
Wireline services	45,874			31	%	56,601			39	%
Coiled tubing services	14,788			10	%	13,226			9	%
Production services	86,916			59	%	90,941			63	%
Consolidated revenues	$	146,568		100	%	$	144,478		100	%

Operating costs:
Domestic drilling	$	22,469		21	%	$	20,898		20	%
International drilling	16,485			15	%	12,961			13	%
Drilling services	38,954			36	%	33,859			33	%
Well servicing	18,896			17	%	15,570			15	%
Wireline services	39,347			36	%	42,486			41	%
Coiled tubing services	11,388			11	%	10,851			11	%
Production services	69,631			64	%	68,907			67	%
Consolidated operating costs	$	108,585		100	%	$	102,766		100	%

Gross margin:
Domestic drilling	$	15,540		41	%	$	15,028		36	%
International drilling	5,158			14	%	4,650			11	%
Drilling services	20,698			55	%	19,678			47	%
Well servicing	7,358			19	%	5,544			13	%
Wireline services	6,527			17	%	14,115			34	%
Coiled tubing services	3,400			9	%	2,375			6	%
Production services	17,285			45	%	22,034			53	%
Consolidated gross margin	$	37,983		100	%	$	41,712		100	%

Consolidated:
Net loss	$	(15,115	)			$	(11,139	)
Adjusted EBITDA ⁽¹⁾	$	19,922				$	23,409

(1) Adjusted EBITDA represents income (loss) before interest expense, income tax (expense) benefit, depreciation and amortization, impairment, and any loss on extinguishment of debt. Adjusted EBITDA is a non-GAAP measure that our management uses to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers. We believe that this measure is useful to investors and analysts in allowing for greater transparency of our core operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does not represent funds available for discretionary use. Adjusted EBITDA may not be comparable to other similarly titled measures reported by other companies.

A reconciliation of net loss, as reported, to Adjusted EBITDA, and to consolidated gross margin, are set forth in the following table:



	Three months ended March 31,
	2019			2018
	(amounts in thousands)
Net loss	$	(15,115	)	$	(11,139	)
Depreciation	22,653			23,747
Impairment	1,046			—
Interest expense	9,885			9,513
Income tax expense	1,453			1,288
Adjusted EBITDA	19,922			23,409
General and administrative	19,758			19,194
Bad debt expense (recovery), net	62			(52		)
Gain on dispositions of property and equipment, net	(1,075		)	(335		)
Other income	(684		)	(504		)
Consolidated gross margin	$	37,983		$	41,712

Consolidated gross margin — Our consolidated gross margin decreased by $3.7 million, or 9%, for the three months ended March 31, 2019 as compared to the corresponding period in 2018, due to a decline in demand for our wireline services, despite an increase in gross margin for all our other business segments. The $3.7 million overall decrease in consolidated gross margin was net of a $3.9 million combined increase in gross margin for our drilling services, well servicing, and coiled tubing services segments.

•

Drilling Services — Our drilling services revenues increased by $6.1 million, or 11%, for the three months ended March 31, 2019 as compared to the corresponding period in 2018, while operating costs increased by $5.1 million, or 15%. The increases in our drilling services revenues and operating costs are primarily due to higher dayrates, a 7% increase in utilization of our international drilling fleet, and the deployment of our newest AC drilling rig in March 2019. The following table provides operating statistics for each of our drilling services segments:



	Three months ended March 31,
	2019			2018
Domestic drilling:
Average number of drilling rigs	16			16
Utilization rate	97		%	100		%
Revenue days	1,420			1,440

Average revenues per day	$	26,767		$	24,949
Average operating costs per day	15,823			14,513
Average margin per day	$	10,944		$	10,436

International drilling:
Average number of drilling rigs	8			8
Utilization rate	81		%	76		%
Revenue days	580			550

Average revenues per day	$	37,316		$	32,020
Average operating costs per day	28,422			23,565
Average margin per day	$	8,894		$	8,455

Our domestic drilling average revenues per day for the three months ended March 31, 2019 increased as compared to the corresponding period in 2018, primarily due to an increase in dayrates on new and extended contracts in 2018 and 2019, except for four rigs that re-priced downward in 2018 from historically high pre-downturn rates. Our average domestic drilling revenues and operating costs per day for the three months ended March 31, 2019 also increased from the corresponding period in 2018 partially due to an increase in mobilization activity during the first quarter of 2019.

Our margin per day during the first quarter of 2019 also benefited from $0.4 million of revenues associated with the early termination of one of our drilling contracts in February 2019.

Our international drilling average revenues, operating costs and margin per day increased for the three months ended March 31, 2019, as compared to the corresponding period in 2018, primarily due to the increase in utilization and increasing dayrates. Our international drilling average margin per day also increased for the three months ended March 31, 2019 as compared to the corresponding period in 2018, in part due to additional costs incurred to deploy a previously idle rig in the first quarter of 2018.

•

Production Services — Our revenues from production services decreased by $4.0 million, or 4%, for the three months ended March 31, 2019 as compared to the corresponding period in 2018, while operating costs increased only marginally. The decrease in revenue is a result of the decreased demand for wireline completion services, for which the decrease was partially offset by increases in demand for both our well servicing and coiled tubing services, which experienced 24% and 12% increases in revenue, respectively. The following table provides operating statistics for each of our production services segments:



	Three months ended March 31,
	2019			2018
Well servicing:
Average number of rigs	125			125
Utilization rate	54		%	47		%
Rig hours	47,064			40,774
Average revenue per hour	$	558		$	518

Wireline services:
Average number of units	105			110
Number of jobs	2,342			2,830
Average revenue per job	$	19,588		$	20,000

Coiled tubing services:
Average number of units	9			14
Revenue days	351			414
Average revenue per day	$	42,131		$	31,947

Our wireline services business segment experienced a 17% decrease in the number of jobs completed, and a 2% decrease in average revenue per job for the three months ended March 31, 2019, as compared to the corresponding period in 2018, primarily due to a decrease in demand for completion-related activity as compared to the corresponding period in 2018, during which time we experienced higher demand for services to complete both newly drilled wells and the remaining inventory of wells which had been drilled but not yet completed.

Our well servicing business experienced an increase in demand during the three months ended March 31, 2019, as compared to the corresponding period in 2018, as the number of completed wells increased during the recovery of our industry, resulting in a larger inventory of producing wells that now require ongoing maintenance. Our well servicing rig hours increased by 15%, while revenues per hour increased by 8%.

Our coiled tubing services business continued to experience an improvement in demand for services provided using our larger diameter coiled tubing units. Although revenue days decreased 15% for the three months ended March 31, 2019, as compared to the corresponding period in 2018, average revenue per day increased 32% primarily due to a larger proportion of the work performed with larger diameter coiled tubing units which typically earn higher revenue rates as compared to smaller diameter coiled tubing units, partially resulting from the addition of two new large diameter coiled tubing units which we placed in service in July and December 2018.

Depreciation expense — Our depreciation expense decreased by $1.1 million for the three months ended March 31, 2019, primarily in our wireline and coiled tubing segments, which currently operate with an overall smaller fleet as compared to the corresponding period in 2018.

Impairment — During the three months ended March 31, 2019, we recognized impairment charges of $1.0 million to reduce the carrying values of certain assets which were classified as held for sale, to their estimated fair values based on expected

sale prices. For more detail, see Note 4, Property and Equipment, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1 Financial Statements, of this Quarterly Report on Form 10-Q.

Income tax expense — Our effective tax rates differ from the applicable U.S. statutory rates due to a number of factors, including valuation allowances, impact of permanent items and the mix of profit and loss between federal, state and international taxing jurisdictions.

General and administrative expense — Our general and administrative expense increased by $0.6 million, or 3%, for the three months ended March 31, 2019, as compared to the corresponding period in 2018, partially due to a $0.3 million increase in our phantom stock compensation expense, attributable to the increase in fair value of our phantom stock unit awards.

Gain on dispositions of property and equipment, net — During the three months ended March 31, 2019, we recognized a net gain of $1.1 million on the disposition of various property and equipment. During the three months ended March 31, 2018, we recognized a net gain of $0.3 million on the disposition of various property and equipment, including the sale of six wireline units and one drilling rig, which was previously held for sale.

Other income — The increase in our other income during the three months ended March 31, 2019, as compared to the corresponding period in 2018, is primarily related to interest earned on the investments made during 2018 in highly-liquid money-market mutual funds.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our financial statements and accompanying notes. Actual results could differ from those estimates. Except for those related to the adoption of ASC Topic 842 discussed below, as of March 31, 2019, there were no significant changes to our critical accounting policies since the date of our annual report on Form 10-K for the year ended December 31, 2018.

Leases — In February 2016, the FASB issued ASU No. 2016-02, Leases, which among other things, requires lessees to recognize substantially all leases on the balance sheet, with expense recognition that is similar to the former lease standard, and aligns the principles of lessor accounting with the principles of the FASB’s new revenue guidance in ASC Topic 606. In July 2018, the FASB issued ASU No. 2018-11, Leases: Targeted Improvements, which provides an option to apply the guidance prospectively, and provides a practical expedient allowing lessors to combine the lease and non-lease components of revenues where the revenue recognition pattern is the same and where the lease component, when accounted for separately, would be considered an operating lease. The practical expedient also allows a lessor to account for the combined lease and non-lease components under ASC Topic 606, Revenue from Contracts with Customers, when the non-lease component is the predominant element of the combined component.

Accounting estimates — Material estimates that are particularly susceptible to significant changes in the near term relate to our estimates of certain variable revenues and amortization periods of certain deferred revenues and costs associated with drilling daywork contacts, our estimates of projected cash flows and fair values for impairment evaluations, our estimate of the valuation allowance for deferred tax assets, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance and our estimate of compensation related accruals.

•

In accordance with ASC Topic 606, Revenue from Contracts with Customers, we estimate certain variable revenues associated with the demobilization of our drilling rigs under daywork drilling contracts. We also make estimates of the applicable amortization periods for deferred mobilization costs, and for mobilization revenues related to cancelable term contracts which represent a material right to our clients. These estimates and assumptions are described in more detail in Note 2, Revenue from Contracts with Customers. In order to make these estimates, management considers all the facts and circumstances pertaining to each particular contract, our past experience and knowledge of current market conditions. For more information, see Note 2, Revenue from Contracts with Customers, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

•

In accordance with ASC Topic 360, Property, Plant and Equipment, we monitor all indicators of potential impairments, and concluded there are no triggers present that require impairment testing as of March 31, 2019, other than the placement of certain assets as held for sale. The most significant inputs used in our impairment analysis include the projected utilization and pricing of our services, as well as the estimated proceeds upon any future sale or disposal of the assets, all of which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. The assumptions we use in the evaluation for impairment are inherently uncertain and require management judgment. Although we believe the assumptions and estimates used in our impairment analysis are reasonable, different assumptions and estimates could materially impact the analysis and resulting conclusions. If commodity prices remain at current levels for an extended period of time, or if the demand for any of our services decreases below what we are currently projecting, our estimated cash flows may decrease, and if any of the foregoing were to occur, we could incur impairment charges on the related assets. For more information, see Note 4, Property and Equipment, of the Notes to

Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

•

As of March 31, 2019, we had $98.1 million and $9.3 million of deferred tax assets related to domestic and foreign net operating losses, respectively, that are available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. As result, as of March 31, 2019, we had a valuation allowance of $66.4 million that offset a portion of our domestic and foreign net deferred tax assets. Since 2017, market conditions and operating results for our Colombian operations have improved, and if they continue to improve, then we may determine that there is sufficient evidence that future taxable income will be generated to utilize our foreign net operating losses which would result in the reversal of the valuation allowance relating to our foreign deferred tax assets. For more information, see Note 5, Valuation Allowances on Deferred Tax Assets, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

•

We use a combination of self-insurance and third-party insurance for various types of coverage. We have stop-loss coverage of $200,000 per covered individual per year under our health insurance and a deductible of $500,000 per occurrence under our workers’ compensation insurance. We have a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance, as well as an additional annual aggregate deductible of $250,000 under our general liability insurance. At March 31, 2019, our accrued insurance premiums and deductibles include approximately $1.6 million of accruals for costs incurred under the self-insurance portion of our health insurance and approximately $3.2 million of accruals for costs associated with our workers’ compensation insurance. We accrue for these costs as claims are incurred using an actuarial calculation that is based on industry and our company’s historical claim development data, and we accrue the cost of administrative services associated with claims processing.

•

Our compensation expense includes estimates for certain of our long-term incentive compensation plans which have performance-based award components dependent upon our performance over a set performance period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates which affect our compensation expense, employee related accruals and equity. The accruals are adjusted based on actual achievement levels at the end of the pre-determined performance periods. Additionally, our phantom stock unit awards are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation, because we expect to settle the awards in cash when they vest, and are remeasured at fair value at the end of each reporting period until they vest. The change in fair value is recognized as a current period compensation expense in our condensed consolidated statements of operations. Therefore, changes in the inputs used to measure fair value can result in volatility in our compensation expense. This volatility increases as the phantom stock awards approach the vesting date. For more information, see Note 9, Stock-Based Compensation Plans, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

Recently Issued Accounting Standards

For a detail of recently issued accounting standards, see Note 1, Organization and Summary of Significant Accounting Policies, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk primarily consists of (i) interest rate risk associated with our variable rate debt and (ii) foreign currency exchange rate risk associated with our Colombian operations.

Interest Rate Risk — We are exposed to interest rate market risk on our variable rate debt. We do not use financial instruments for trading or other speculative purposes. As of March 31, 2019, the principal amount under our Term Loan was $175 million, which is our only variable rate debt with an outstanding balance. The impact of a hypothetical 1% increase or decrease in interest rates on this amount of debt would have resulted in a corresponding increase or decrease, respectively, in interest expense of approximately $0.4 million during the three months ended March 31, 2019. This potential increase or decrease is based on the simplified assumption that the level of variable rate debt remains constant with an immediate across-the-board interest rate increase or decrease as of January 1, 2019.

Foreign Currency Risk — While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter into transactions denominated in Colombian Pesos. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. As a result, Colombian Peso denominated transactions are affected by changes in exchange rates. We generally accept the exposure to exchange rate movements without using derivative financial instruments to manage this risk. Therefore, both positive and negative movements in the Colombian Peso currency exchange rate against the U.S. dollar have and will continue to affect the reported amount of revenues, expenses, profit, and assets and liabilities in our consolidated financial statements. The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in net foreign currency gains of $0.3 million for the three months ended March 31, 2019.


ITEM 4.	CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2019, to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

In the ordinary course of business, we may make changes to our systems and processes to improve controls and increase efficiency, and make changes to our internal controls over financial reporting in order to ensure that we maintain an effective internal control environment.

We adopted ASU No. 2016-02, Leases, and its related amendments, as of January 1, 2019, which we discuss more fully in Note 1, Organization and Summary of Significant Accounting Policies, of the Notes to Unaudited Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q. During this implementation and upon adoption of the new standard, we assessed and modified our internal controls in order to facilitate adoption of the new lease accounting standard, primarily related to the implementation of a new lease accounting system and modifications to the related payment and accounting processes.

Other than the impact of adopting ASC Topic 842 as described above, there has been no change in our internal control over financial reporting that occurred during the three months ended March 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

From time to time, we are involved in routine litigation or subject to disputes or claims arising out of our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flows.


ITEM 1A.	RISK FACTORS

Not applicable.


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

We did not make any unregistered sales of equity securities during the quarter ended March 31, 2019. The following table provides information relating to our repurchase of common shares during the quarter ended March 31, 2019:



Period	Total Number of Shares Purchased (1)	Average Price Paid per Share (2)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 - January 31	84,266	$	1.42	—	—
February 1 - February 28	593	$	1.50	—	—
March 1 - March 31	—	$	—	—	—
Total	84,859	$	1.42	—	—


(1)	The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended March 31, 2019, to satisfy the employees’ tax withholding obligations in connection with the vesting of share-based compensation awards, which we repurchased based on the fair market value on the date the relevant transaction occurred.


(2)	The calculation of the average price paid per share does not give effect to any fees, commissions or other costs associated with the repurchase of such shares.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not applicable.


ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.	OTHER INFORMATION

Not applicable.


ITEM 6.	EXHIBITS

The following exhibits are filed as part of this report:



Exhibit Number		Description

3.1*	-	Restated Articles of Incorporation of Pioneer Energy Services Corp. (Form 8-K dated May 22, 2017 (File No. 1-8182, Exhibit 3.1)).

3.2*	-	Amended and Restated Bylaws of Pioneer Energy Services Corp. (Form 8-K dated July 30, 2012 (File No. 1-8182, Exhibit 3.2)).

4.1*	-	Form of Certificate representing Common Stock of Pioneer Energy Services Corp. (Form 10-Q dated August 7, 2012 (File No. 1-8182, Exhibit 4.1)).

4.2*	-	Indenture, dated March 18, 2014, by and among Pioneer Energy Services Corp., the subsidiaries named as guarantors therein and Wells Fargo Bank, National Association, as trustee (Form 8-K dated March 18, 2014 (File No. 1-8182, Exhibit 4.1)).

4.3*	-	Registration Rights Agreement, dated March 18, 2014, by and among Pioneer Energy Services Corp., the subsidiaries named as guarantors therein and the initial purchasers party thereto (Form 8-K dated March 18, 2014 (File No. 1-8182, Exhibit 10.1)).

10.1**+		Pioneer Energy Services Corp. 2007 Incentive Plan Form of Time-Based Phantom Stock Unit Award Agreement

31.1**	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.

31.2**	-	Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.

32.1#	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2#	-	Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101**	-	The following financial statements from Pioneer Energy Services Corp.’s Form 10-Q for the quarter ended March 31, 2019, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Shareholders’ Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to Condensed Consolidated Financial Statements.

*	Incorporated by reference to the filing indicated.
**	Filed herewith.
#	Furnished herewith.
+	Management contract or compensatory plan or arrangement.

SIGNATURES

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.

PIONEER ENERGY SERVICES CORP.

/s/ Lorne E. Phillips

Lorne E. Phillips

Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized Officer)

Dated: May 2, 2019